P. Skoczylas, F. Alhanati, J. Sheldon, F. Trevisan
Operators generally want to reduce well down-time and repair/replacement costs by improving the reliability of their Artificial lift (AL) systems. In order to understand if actions taken to improve reliability are effective, one must track the AL system run-life. This paper discusses run-life measures commonly used in the AL industry and provides recommendations for when each run-life measure should be used. Synthetic data, generated using random runtime and failure data from known statistical distributions, is used to illustrate the effect of various factors, such as selecting equipment with higher inherent reliability, on the resulting measured run-life. This paper also presents several pitfalls that should be avoided when selecting run-life measures for comparing equipment or implementing operator-vendor alliance contracts.
{"title":"Use of Run-Life Measures in Estimating Artificial Lift System Reliability","authors":"P. Skoczylas, F. Alhanati, J. Sheldon, F. Trevisan","doi":"10.2118/190962-MS","DOIUrl":"https://doi.org/10.2118/190962-MS","url":null,"abstract":"\u0000 Operators generally want to reduce well down-time and repair/replacement costs by improving the reliability of their Artificial lift (AL) systems. In order to understand if actions taken to improve reliability are effective, one must track the AL system run-life. This paper discusses run-life measures commonly used in the AL industry and provides recommendations for when each run-life measure should be used. Synthetic data, generated using random runtime and failure data from known statistical distributions, is used to illustrate the effect of various factors, such as selecting equipment with higher inherent reliability, on the resulting measured run-life. This paper also presents several pitfalls that should be avoided when selecting run-life measures for comparing equipment or implementing operator-vendor alliance contracts.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121117201","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}
This study presents a transient inflow-performance relationship (IPR) model using the steady-state solution to the diffusivity equation on a periodic varying well-flowing pressure. A wellbore model can be coupled to accurately depict the deliverability from wells with an artificial-lift system (ALS), such as gas lift and plunger lift. The commercial simulators allowed verification of model results and field data validated the solution approach. For verification of this simplified IPR modeling approach, we first attempted to replicate two-step rate flow and shut-in periods, such as those associated with a transient flow test. Our model successfully reproduced those transient pressure profiles obtained from a rigorous superposition approach, generated with an analytical model using a commercial software package. Thereafter, we replicated the results of a coupled wellbore/reservoir model for a gas-lift well, using a numerical simulator. The difference between the results of rigorous simulators and our simplified transient-IPR model turned out to be well within engineering accuracy. Field data from two plunger lift operations validated the transient-IPR model presented in this study. One important aspect to note is that a smaller period of oscillation translates into a more significant error between the traditional steady-state IPR model and the actual transient-IPR model. This finding suggested the need for the accuracy of the transient-IPR model in ALS to express the realistic rates and pressures. By capturing the essence of transient behavior, it is possible to combat downhole tool failures due to large pressure fluctuations or issues with surface metering due to higher than expected rates.
{"title":"Modeling Transient Inflow Performance Relationship in Artificial-Lift Systems","authors":"Z. Xiang, C. Kabir","doi":"10.2118/190916-MS","DOIUrl":"https://doi.org/10.2118/190916-MS","url":null,"abstract":"\u0000 This study presents a transient inflow-performance relationship (IPR) model using the steady-state solution to the diffusivity equation on a periodic varying well-flowing pressure. A wellbore model can be coupled to accurately depict the deliverability from wells with an artificial-lift system (ALS), such as gas lift and plunger lift. The commercial simulators allowed verification of model results and field data validated the solution approach.\u0000 For verification of this simplified IPR modeling approach, we first attempted to replicate two-step rate flow and shut-in periods, such as those associated with a transient flow test. Our model successfully reproduced those transient pressure profiles obtained from a rigorous superposition approach, generated with an analytical model using a commercial software package. Thereafter, we replicated the results of a coupled wellbore/reservoir model for a gas-lift well, using a numerical simulator. The difference between the results of rigorous simulators and our simplified transient-IPR model turned out to be well within engineering accuracy.\u0000 Field data from two plunger lift operations validated the transient-IPR model presented in this study. One important aspect to note is that a smaller period of oscillation translates into a more significant error between the traditional steady-state IPR model and the actual transient-IPR model. This finding suggested the need for the accuracy of the transient-IPR model in ALS to express the realistic rates and pressures. By capturing the essence of transient behavior, it is possible to combat downhole tool failures due to large pressure fluctuations or issues with surface metering due to higher than expected rates.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"114 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130032918","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. F. Vargas, J. Duran, A. Simpson, R. Santos, J. Doval, Loewe Muñoz, A. E. P. Jerez, C. Rativa, N. Hernandez, Rozo Rozo, D. Ríos
This paper presents a successful application and the lessons learned during a pilot test under which a new electrical submersible pumping technology was installed in 4 wells. These helico-axial downhole pumps, V-Pump, were installed under a program of new technologies testing, which aimed for artificial lift run life extension in an extremely high sand-producing field under current cost constraints. The oil price turndown forced Casabe Field to leave some wells inactive, even though they still have significant reserves. The cause of this decision was the expenses associated to the high frequency of interventions required due to the adverse sand production effects on the artificial lift systems. Due to the low run life of conventional artificial lift systems that are customary to use in the field, it was necessary to search for emerging technologies that would meet the challenge presented. A screening process for new technologies were conducted, and after that, these pumps were installed in four wells, which were continuously monitored with downhole temperature, vibration and pressure sensors, fluid levels measurement, VSD readings and production tests, which would allow to understand the technology performance to achieve the desired run life, oil production gain, and to obtain lessons learned to design the second phase of the testing project. The use of this innovative pumping technology extended the run life in the pilot wells between 180% and 420%, allowing the production of their remaining oil reserves, and giving a new approach in the production strategy of the field. One well is still running after 13 months. Also, based on the on the information collected during the well production phase, through downhole sensors and VSD parameters, and the findings during the pump's dismantle, some recommendations were made to improve the performance in the second phase of the project. Recommendations include both improvements in the pump design and to the screening process of candidate wells.
{"title":"Getting Wells Back to Production Using an Innovative Artificial Lift System for Recovering Inactive Wells","authors":"A. F. Vargas, J. Duran, A. Simpson, R. Santos, J. Doval, Loewe Muñoz, A. E. P. Jerez, C. Rativa, N. Hernandez, Rozo Rozo, D. Ríos","doi":"10.2118/190961-MS","DOIUrl":"https://doi.org/10.2118/190961-MS","url":null,"abstract":"\u0000 This paper presents a successful application and the lessons learned during a pilot test under which a new electrical submersible pumping technology was installed in 4 wells. These helico-axial downhole pumps, V-Pump, were installed under a program of new technologies testing, which aimed for artificial lift run life extension in an extremely high sand-producing field under current cost constraints.\u0000 The oil price turndown forced Casabe Field to leave some wells inactive, even though they still have significant reserves. The cause of this decision was the expenses associated to the high frequency of interventions required due to the adverse sand production effects on the artificial lift systems.\u0000 Due to the low run life of conventional artificial lift systems that are customary to use in the field, it was necessary to search for emerging technologies that would meet the challenge presented. A screening process for new technologies were conducted, and after that, these pumps were installed in four wells, which were continuously monitored with downhole temperature, vibration and pressure sensors, fluid levels measurement, VSD readings and production tests, which would allow to understand the technology performance to achieve the desired run life, oil production gain, and to obtain lessons learned to design the second phase of the testing project.\u0000 The use of this innovative pumping technology extended the run life in the pilot wells between 180% and 420%, allowing the production of their remaining oil reserves, and giving a new approach in the production strategy of the field. One well is still running after 13 months.\u0000 Also, based on the on the information collected during the well production phase, through downhole sensors and VSD parameters, and the findings during the pump's dismantle, some recommendations were made to improve the performance in the second phase of the project. Recommendations include both improvements in the pump design and to the screening process of candidate wells.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124204590","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 aim of this paper is to show how tubing (TBG) installation has evolved, with the problems and learning processes experienced along the brief history of exploitation of the Vaca Muerta formation in the Loma Campana field. The production behavior of wells from Vaca Muerta consists initially of flows close to 100m3/d, with sufficient pressure to produce natural flowing by the 5" casing, controlled by an orifice at wellhead. Once the flowing period finishes, the well starts using mechanical pumping to keep producing with this system in the long term. Wells with a higher gas oil rate (GOR) are converted to plunger lift before resorting to mechanical pumping. Due to the fact that a well experiences different extraction stages in a relatively short period of time (flowing by casing - flowing by TBG - Plunger Lift - mechanical pumping), it is necessary to find an installation that is flexible enough to allow switching from one stage to the other with the least amount of slickline and pulling interventions. Likewise, the installation should be able to minimize the effects of sand and gas existing in Vaca Muerta, which affect the performance of mechanical pumping. Thus, this paper shows how TBG installations have changed to finally reach the current installation. This installation allows the conversion of a flowing by TGB installation into a mechanical pumping installation with gas buster, poor boy type, using slickline intervention and pump and rod running, thus avoiding the necessity of moving the TBG.
{"title":"Innovative Downhole Design for Optimizing ALS Installation at Shale Oil Wells","authors":"I. Cuneo, J. Ardito, G. Rivero","doi":"10.2118/190954-MS","DOIUrl":"https://doi.org/10.2118/190954-MS","url":null,"abstract":"\u0000 The aim of this paper is to show how tubing (TBG) installation has evolved, with the problems and learning processes experienced along the brief history of exploitation of the Vaca Muerta formation in the Loma Campana field.\u0000 The production behavior of wells from Vaca Muerta consists initially of flows close to 100m3/d, with sufficient pressure to produce natural flowing by the 5\" casing, controlled by an orifice at wellhead.\u0000 Once the flowing period finishes, the well starts using mechanical pumping to keep producing with this system in the long term. Wells with a higher gas oil rate (GOR) are converted to plunger lift before resorting to mechanical pumping.\u0000 Due to the fact that a well experiences different extraction stages in a relatively short period of time (flowing by casing - flowing by TBG - Plunger Lift - mechanical pumping), it is necessary to find an installation that is flexible enough to allow switching from one stage to the other with the least amount of slickline and pulling interventions.\u0000 Likewise, the installation should be able to minimize the effects of sand and gas existing in Vaca Muerta, which affect the performance of mechanical pumping.\u0000 Thus, this paper shows how TBG installations have changed to finally reach the current installation. This installation allows the conversion of a flowing by TGB installation into a mechanical pumping installation with gas buster, poor boy type, using slickline intervention and pump and rod running, thus avoiding the necessity of moving the TBG.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121923045","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 Tourmaline Oil Corporation's light oil play (The Field) utilizes electrical submersible pumps (ESP's) for the dewatering and initial production (IP) phase. Sucker rod pumps are then used as the main artificial lift technology to produce The Field. The typical procedure is to convert these wells to pump and rods after the first ESP failure or after the well ceases to flow naturally. Constant changing of the lift systems on each well incurs costs, requires manpower and creates exposure with the need for surface facilities work. The recent economic downturn applied focus on reducing costs while optimizing production. A single wellhead that could accommodate flowing wells, ESP's, rod pumps and gas lift without the need to change the flowline configuration would save money and minimize production downtime. To develop this technology Tourmaline collaborated with industry leaders in wellhead penetration and rod pumping blow out preventers (BOP's) to design and engineer such a wellhead. The multi-function BOP will master ESP, rod pumps, natural flow and gas lift. After the multi-function BOP development was complete it was trialed in a controlled environment then installed on multiple wells within The Field. The product developed consists of combination tubing hanger and production wellhead. The multi-function wellhead includes dual master valves, dual rod BOP's, ESP capillary feed-through and gas lift capabilities with two flowline outlets. The final product is only thirty one and a half inches in height, making it compact, and operationally ergonomic. There have also been efficiencies realized from this wellhead including modular wellhead skids, downhole artificial lift combination deployment and reduced servicing costs. The surface conversion costs have been reduced by 95%. Due to the unconventional well flowing regimes and artificial lift practices Tourmaline Oil faces in The Field the need for new technology was identified. By teaming up with industry leaders an innovative and unique multif-function BOP wellhead was developed. The product has been installed throughout The Field with great success and has inspired other advancements in oil field efficiency.
{"title":"Reducing Artificial Lift Surface Conversion Costs in a Unconventional Oil Field","authors":"C. Weiss, T. McGee, K. McAdam","doi":"10.2118/190928-MS","DOIUrl":"https://doi.org/10.2118/190928-MS","url":null,"abstract":"\u0000 The Tourmaline Oil Corporation's light oil play (The Field) utilizes electrical submersible pumps (ESP's) for the dewatering and initial production (IP) phase. Sucker rod pumps are then used as the main artificial lift technology to produce The Field. The typical procedure is to convert these wells to pump and rods after the first ESP failure or after the well ceases to flow naturally. Constant changing of the lift systems on each well incurs costs, requires manpower and creates exposure with the need for surface facilities work.\u0000 The recent economic downturn applied focus on reducing costs while optimizing production. A single wellhead that could accommodate flowing wells, ESP's, rod pumps and gas lift without the need to change the flowline configuration would save money and minimize production downtime. To develop this technology Tourmaline collaborated with industry leaders in wellhead penetration and rod pumping blow out preventers (BOP's) to design and engineer such a wellhead. The multi-function BOP will master ESP, rod pumps, natural flow and gas lift. After the multi-function BOP development was complete it was trialed in a controlled environment then installed on multiple wells within The Field.\u0000 The product developed consists of combination tubing hanger and production wellhead. The multi-function wellhead includes dual master valves, dual rod BOP's, ESP capillary feed-through and gas lift capabilities with two flowline outlets. The final product is only thirty one and a half inches in height, making it compact, and operationally ergonomic. There have also been efficiencies realized from this wellhead including modular wellhead skids, downhole artificial lift combination deployment and reduced servicing costs. The surface conversion costs have been reduced by 95%.\u0000 Due to the unconventional well flowing regimes and artificial lift practices Tourmaline Oil faces in The Field the need for new technology was identified. By teaming up with industry leaders an innovative and unique multif-function BOP wellhead was developed. The product has been installed throughout The Field with great success and has inspired other advancements in oil field efficiency.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129042382","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}
L. Camilleri, H. Gong, Nora Al-Maqsseed, Abdulla M. Al-Jazzaf
To maximize electrical submersible pump (ESP) uptime and production in North Kuwait's diverse reservoir conditions, it was necessary to combine variable speed drive (VSD) feedback control functionality with reservoir knowledge and real-time data and subsequently develop an operating strategy tailored to individual wells. The case studies in this paper show how well performance can be stabilized and production increased by incorporating motor current and downhole pressure into the VSD frequency control loop. In North Kuwait fields, engineers studied wells with ESPs running in unstable condition or suffering frequent tripping due to underload or high temperature. Their ESP design datasheets, production test results, historical VSD running parameters, and downhole gauge data were used to calibrate pump and well performance models and identify the pump operating point. From these simulation results, the VSD feedback control loop function was optimized to minimize tripping and/or enhance stability, thereby increasing production. The main causes of well instability and ESP downtime in North Kuwait are declining bottom hole flowing pressure and gas interference. The case studies illustrate how to select the appropriate VSD frequency feedback object function for each of these cases. For weak inflow, the VSD is configured to maintain constant intake pressure, especially where the intake pressure is less than 500 psia. For ESPs suffering from gas interference, constant current was implemented to avoid gas locking. The before and after results from the case study wells demonstrate the effectiveness of this technique for well stabilization and associated production increase. After the study, this method was implemented on 60 wells and resulted in a 21% reduction in the number of ESP trips over 6 months and an associated increase in uptime from 92% to 97%. This case study describes a workflow that integrates ESP historical running data, reservoir knowledge, and VSD feedback control functions to increase well uptime by preventing ESP tripping. In addition, the workflow enhances ESP system operating stability and optimizes the reservoir drawdown, which offers the operator a viable option to achieve production objectives.
{"title":"Tuning VSDs in ESP Wells to Optimize Oil Production—Case Studies","authors":"L. Camilleri, H. Gong, Nora Al-Maqsseed, Abdulla M. Al-Jazzaf","doi":"10.2118/190940-MS","DOIUrl":"https://doi.org/10.2118/190940-MS","url":null,"abstract":"\u0000 To maximize electrical submersible pump (ESP) uptime and production in North Kuwait's diverse reservoir conditions, it was necessary to combine variable speed drive (VSD) feedback control functionality with reservoir knowledge and real-time data and subsequently develop an operating strategy tailored to individual wells. The case studies in this paper show how well performance can be stabilized and production increased by incorporating motor current and downhole pressure into the VSD frequency control loop.\u0000 In North Kuwait fields, engineers studied wells with ESPs running in unstable condition or suffering frequent tripping due to underload or high temperature. Their ESP design datasheets, production test results, historical VSD running parameters, and downhole gauge data were used to calibrate pump and well performance models and identify the pump operating point. From these simulation results, the VSD feedback control loop function was optimized to minimize tripping and/or enhance stability, thereby increasing production.\u0000 The main causes of well instability and ESP downtime in North Kuwait are declining bottom hole flowing pressure and gas interference. The case studies illustrate how to select the appropriate VSD frequency feedback object function for each of these cases. For weak inflow, the VSD is configured to maintain constant intake pressure, especially where the intake pressure is less than 500 psia. For ESPs suffering from gas interference, constant current was implemented to avoid gas locking. The before and after results from the case study wells demonstrate the effectiveness of this technique for well stabilization and associated production increase. After the study, this method was implemented on 60 wells and resulted in a 21% reduction in the number of ESP trips over 6 months and an associated increase in uptime from 92% to 97%.\u0000 This case study describes a workflow that integrates ESP historical running data, reservoir knowledge, and VSD feedback control functions to increase well uptime by preventing ESP tripping. In addition, the workflow enhances ESP system operating stability and optimizes the reservoir drawdown, which offers the operator a viable option to achieve production objectives.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"167 6-7","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114037973","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}
J. Goldney, B. Mohando, G. Cometto, M. Ballarini, R. Mazzola
A novel and flexible completion design for HGOR Wells is presented to cover all the gas well production stages in order to avoid rig interventions during natural flow which would reduce gas production potential due to water influx into the reservoir. The objective of this paper is to introduce the proposed completion designs so other engineers can apply and improve them in their HGOR wells, maximizing gas production and reducing costs. After studying the conversions from natural flowing wells to Artificial Lifted wells in which gas production was never recovered, the behavior was determined to be from damage (water blockage) in the near wellbore caused by the fluids used in the rig operations. A decision was made to anticipate the inherent problems through a flexible completion design that allows for the production of different reservoirs, with tubing and/or annular flow, plunger lift, gas lift, and changing to Sucker Rod Pumping without moving tubing or killing the well, especially in the gas reservoirs. The flexible completions also allowed for further studies of the well and proposed interventions to assist the flow.
{"title":"Innovative Well Designs for HGOR: Extending Gas Production with Common Gas Well Deliquification Techniques","authors":"J. Goldney, B. Mohando, G. Cometto, M. Ballarini, R. Mazzola","doi":"10.2118/190966-MS","DOIUrl":"https://doi.org/10.2118/190966-MS","url":null,"abstract":"\u0000 A novel and flexible completion design for HGOR Wells is presented to cover all the gas well production stages in order to avoid rig interventions during natural flow which would reduce gas production potential due to water influx into the reservoir.\u0000 The objective of this paper is to introduce the proposed completion designs so other engineers can apply and improve them in their HGOR wells, maximizing gas production and reducing costs.\u0000 After studying the conversions from natural flowing wells to Artificial Lifted wells in which gas production was never recovered, the behavior was determined to be from damage (water blockage) in the near wellbore caused by the fluids used in the rig operations.\u0000 A decision was made to anticipate the inherent problems through a flexible completion design that allows for the production of different reservoirs, with tubing and/or annular flow, plunger lift, gas lift, and changing to Sucker Rod Pumping without moving tubing or killing the well, especially in the gas reservoirs.\u0000 The flexible completions also allowed for further studies of the well and proposed interventions to assist the flow.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114113026","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 objective of this study is to experimentally investigate the fall velocities of several type of plungers in various stagnant liquids and at different dynamic operating conditions. Six different plungers were evaluated, namely, new and used brush, new and used dual pad, new and used spiral, and new two piece type plungers. The experimental studies were carried out using two different facilities. First, a simple plunger setup was used to measure the fall velocity of different plungers. This experimental configuration allows the use of different liquids at stagnant conditions (water, water with flowing air and oil). The experimental results show that plunger fall velocity in water is about 4% of the plunger velocity in air. Under a bubbling column and for all plunger types, the fall velocity fluctuates as the air passes through the plunger yielding, in some cases, an average velocity similar to the water case. The fall velocities in low and medium viscosity oils are 60% and 42% of the average velocity in water, respectively. Second, a comprehensive experimental facility was designed and constructed to study the plunger under dynamic operating conditions (or cycles) and at different fluid pressures (air). When the plunger fall velocity was studied under a cyclic operating conditions, the resultant fall velocity is about 60% of the velocity observed in only air, but 30 times larger than the corresponding velocity in stagnant oil. Comparatively, the fastest conventional plunger is the spiral type, whereas the conventional sealing types (pad and brush) are the slowest ones. In addition, the effect of pressure is substantial and the fall velocity of the plunger rapidly decreases as the gas phase (air) pressure increases. Based on the experimental observations and data analysis, it was found that the fall velocity depends mainly on the type of plunger, air phase pressure, thickness of the liquid film on tubing wall, viscosity of the liquid, and density of the gas phase. Plunger lift is one of the most used deliquification method for gas wells. However, only a few experimental studies have been found in the literature. None of them attempt the comparison of different plungers. This study present a new set of data that helps to understand the behavior of the different types of plungers.
{"title":"Plunger Fall Velocity Studies in Vertical Wells","authors":"R. Acosta, E. Pereyra, C. Sarica","doi":"10.2118/190949-MS","DOIUrl":"https://doi.org/10.2118/190949-MS","url":null,"abstract":"\u0000 The objective of this study is to experimentally investigate the fall velocities of several type of plungers in various stagnant liquids and at different dynamic operating conditions. Six different plungers were evaluated, namely, new and used brush, new and used dual pad, new and used spiral, and new two piece type plungers. The experimental studies were carried out using two different facilities.\u0000 First, a simple plunger setup was used to measure the fall velocity of different plungers. This experimental configuration allows the use of different liquids at stagnant conditions (water, water with flowing air and oil). The experimental results show that plunger fall velocity in water is about 4% of the plunger velocity in air. Under a bubbling column and for all plunger types, the fall velocity fluctuates as the air passes through the plunger yielding, in some cases, an average velocity similar to the water case. The fall velocities in low and medium viscosity oils are 60% and 42% of the average velocity in water, respectively. Second, a comprehensive experimental facility was designed and constructed to study the plunger under dynamic operating conditions (or cycles) and at different fluid pressures (air). When the plunger fall velocity was studied under a cyclic operating conditions, the resultant fall velocity is about 60% of the velocity observed in only air, but 30 times larger than the corresponding velocity in stagnant oil.\u0000 Comparatively, the fastest conventional plunger is the spiral type, whereas the conventional sealing types (pad and brush) are the slowest ones. In addition, the effect of pressure is substantial and the fall velocity of the plunger rapidly decreases as the gas phase (air) pressure increases. Based on the experimental observations and data analysis, it was found that the fall velocity depends mainly on the type of plunger, air phase pressure, thickness of the liquid film on tubing wall, viscosity of the liquid, and density of the gas phase.\u0000 Plunger lift is one of the most used deliquification method for gas wells. However, only a few experimental studies have been found in the literature. None of them attempt the comparison of different plungers. This study present a new set of data that helps to understand the behavior of the different types of plungers.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129418046","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}
Plungerlift was installed in conjunction with gaslift to improve efficiency in delifiquification of unconventional gas wells. The dual artificial lift methods were implemented to more aggressively reduce bottom-hole pressure, in order to increase production in Barnett Shale wells. Wells are selected based on a series of metrics, including gas-liquid ratio, fluid production, casing pressure and differential between casing and line pressure. The basics of both plunger-assisted gaslift (PAGL) and gas-assisted plungerlift (GAPL) both utilize injection gas and a plunger to optimize the well. Plunger-assisted gaslift is continuous injection and continuous plungerlift. PAGL is implemented on higher gas and fluid producers. These wells require the addition of injection gas to raise the critical velocity needed to lift both the plunger and the fluid of the well. GAPL is intermittent injection and conventional plungerlift. It is implemented on lower gas and fluid producers. Gas is only injected during certain phases of the plunger cycle to supplement the wellbore inflow and successfully lift fluid and plunger to surface. This presentation will describe the process and results of installing PAGL and GAPL on specific case studies in the Barnett Shale. Historical data, including production, pressures and producing methods will be presented, to compare the results of prior lift methods to those of PAGL or GAPL. By implementing PAGL and GAPL, bottom-hole pressure was successfully lowered and production increased. A secondary benefit is the reduced quantity of gaslift that results in lower operating costs and a more-effective use of horsepower. The results of over-injection in unconventional wells will also be notated. This presentation will detail the benefits and results of dual artificial lift that can efficiently and economically add value to a field.
{"title":"Plunger-Assisted Gas Lift and Gas-Assisted Plunger Lift","authors":"M. Burns","doi":"10.2118/190937-MS","DOIUrl":"https://doi.org/10.2118/190937-MS","url":null,"abstract":"\u0000 Plungerlift was installed in conjunction with gaslift to improve efficiency in delifiquification of unconventional gas wells. The dual artificial lift methods were implemented to more aggressively reduce bottom-hole pressure, in order to increase production in Barnett Shale wells.\u0000 Wells are selected based on a series of metrics, including gas-liquid ratio, fluid production, casing pressure and differential between casing and line pressure. The basics of both plunger-assisted gaslift (PAGL) and gas-assisted plungerlift (GAPL) both utilize injection gas and a plunger to optimize the well. Plunger-assisted gaslift is continuous injection and continuous plungerlift. PAGL is implemented on higher gas and fluid producers. These wells require the addition of injection gas to raise the critical velocity needed to lift both the plunger and the fluid of the well. GAPL is intermittent injection and conventional plungerlift. It is implemented on lower gas and fluid producers. Gas is only injected during certain phases of the plunger cycle to supplement the wellbore inflow and successfully lift fluid and plunger to surface.\u0000 This presentation will describe the process and results of installing PAGL and GAPL on specific case studies in the Barnett Shale. Historical data, including production, pressures and producing methods will be presented, to compare the results of prior lift methods to those of PAGL or GAPL. By implementing PAGL and GAPL, bottom-hole pressure was successfully lowered and production increased. A secondary benefit is the reduced quantity of gaslift that results in lower operating costs and a more-effective use of horsepower. The results of over-injection in unconventional wells will also be notated.\u0000 This presentation will detail the benefits and results of dual artificial lift that can efficiently and economically add value to a field.","PeriodicalId":373819,"journal":{"name":"Day 3 Thu, August 30, 2018","volume":"44 5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132283670","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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