When the oil price is low, cost optimization is vital, especially in mature oil fields. Reducing lifting costs by increasing the mean time between failure and the overall system efficiency helps to keep wells economical and increase the final recovery factor. A significant portion of artificially lifted wells currently use sucker rod pumping systems. Although its efficiency is in the upper range, there is still room for improvement compared with other artificial-lift systems. This paper presents the field-tested sucker rod antibuckling system (SRABS), which prevents buckling of the entire sucker rod string, achieved by a redesign of the standing valve, the advantageous use of the dynamic liquid level, and, on a case-by-case basis, application of a tension element. The system allows full buckling prevention and a reduction of the overall stresses in the sucker rod string. The resulting reduction in the number of well interventions combined with the higher system efficiency prolongs economic production in mature oil fields, even in times of low oil prices. The analysis of SRABS, using finite-element simulations, showed a significant increase in system efficiency. The SRABS performance and wear tests under large-scale conditions were performed at Montanuniversität Leoben’s Pump Test Facility and in the oil field. The results of intensive laboratory testing were used to optimize the pump-body geometry and improve the wear resistance by selecting optimal materials for the individual pump components. The ongoing field-test evaluation confirmed the theoretical approach and showed the benefits achieved by using SRABS. SRABS itself can be applied within every sucker rod pumping system; the installation is as convenient as a standard pump, and manufacturing costs are comparable with those of a standard pump. This paper shows improved performance of the SRABS pumping system compared with a standard sucker rod pump. SRABS is one of the first systems that prevents the sucker rod string from buckling without any additional equipment, such as sinker bars. Testing of SRABS has identified significant benefits compared with standard sucker rod pumps.
{"title":"Sucker Rod Antibuckling System: Development and Field Application","authors":"C. Langbauer, R. Fruhwirth, L. Volker","doi":"10.2118/205352-PA","DOIUrl":"https://doi.org/10.2118/205352-PA","url":null,"abstract":"When the oil price is low, cost optimization is vital, especially in mature oil fields. Reducing lifting costs by increasing the mean time between failure and the overall system efficiency helps to keep wells economical and increase the final recovery factor. A significant portion of artificially lifted wells currently use sucker rod pumping systems. Although its efficiency is in the upper range, there is still room for improvement compared with other artificial-lift systems.\u0000 This paper presents the field-tested sucker rod antibuckling system (SRABS), which prevents buckling of the entire sucker rod string, achieved by a redesign of the standing valve, the advantageous use of the dynamic liquid level, and, on a case-by-case basis, application of a tension element. The system allows full buckling prevention and a reduction of the overall stresses in the sucker rod string.\u0000 The resulting reduction in the number of well interventions combined with the higher system efficiency prolongs economic production in mature oil fields, even in times of low oil prices. The analysis of SRABS, using finite-element simulations, showed a significant increase in system efficiency. The SRABS performance and wear tests under large-scale conditions were performed at Montanuniversität Leoben’s Pump Test Facility and in the oil field. The results of intensive laboratory testing were used to optimize the pump-body geometry and improve the wear resistance by selecting optimal materials for the individual pump components. The ongoing field-test evaluation confirmed the theoretical approach and showed the benefits achieved by using SRABS. SRABS itself can be applied within every sucker rod pumping system; the installation is as convenient as a standard pump, and manufacturing costs are comparable with those of a standard pump.\u0000 This paper shows improved performance of the SRABS pumping system compared with a standard sucker rod pump. SRABS is one of the first systems that prevents the sucker rod string from buckling without any additional equipment, such as sinker bars. Testing of SRABS has identified significant benefits compared with standard sucker rod pumps.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43274072","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Progressing cavity pump (PCP) is the essential booster equipment in oil–gas mixing delivery. Changes in relevant parameters in PCP operations directly affect the working performance and service life of the pump. On the basis of computational fluid dynamics (CFD) in this study, we apply dynamic grid technology to establish a 3D flow field numerical calculation model for the CQ11-2.4J PCP, which is used in the field of the Hounan Operation Area in Changqing oil field, China. The effects of several operating parameters, such as oil viscosity, pump rotation speed, differential pump pressure, and void fraction of oil, on the pressure and the velocity distribution of the PCP flow field are examined. Various performance parameters in the transport of the oil–gas two-phase mixture are used in the analysis, including volumetric flow rate, slippage, shaft power, volumetric efficiency, and system efficiency. The results show that the pressure and speed distribution in the pump chamber of the PCP is relatively homogenous under different working conditions, whereas the pressure and speed exhibited sharp changes at the stator and rotor sealing line and adjacent areas in the pump chamber. Increasing the viscosity of the oil and the speed of the rotor can effectively improve the flow characteristics of the PCP, but extremely high pump rotation speed would cause a decline in system efficiency. Increasing the differential pressure and the void fraction of oil would result in a decrease in the volumetric flow rate and efficiency of the PCP. Considering the variation law of the PCP's performance parameters, the optimal interval for each operating parameter of the PCP is as follows: Oil viscosity at 50–100 mPa·s, pump rotation speed at 200–300 rev/min, differential pressure at 0.2–0.3 MPa, and the void fraction of oil not more than 50%. This research can provide technical support for the optimization of the working conditions of the PCP on site.
{"title":"Flow Field Numerical Simulation and Performance Analysis of Progressing Cavity Pump","authors":"Wu Liu, M. Shu, Yong Sun, Yuanbo Fan","doi":"10.2118/205359-PA","DOIUrl":"https://doi.org/10.2118/205359-PA","url":null,"abstract":"\u0000 Progressing cavity pump (PCP) is the essential booster equipment in oil–gas mixing delivery. Changes in relevant parameters in PCP operations directly affect the working performance and service life of the pump. On the basis of computational fluid dynamics (CFD) in this study, we apply dynamic grid technology to establish a 3D flow field numerical calculation model for the CQ11-2.4J PCP, which is used in the field of the Hounan Operation Area in Changqing oil field, China. The effects of several operating parameters, such as oil viscosity, pump rotation speed, differential pump pressure, and void fraction of oil, on the pressure and the velocity distribution of the PCP flow field are examined. Various performance parameters in the transport of the oil–gas two-phase mixture are used in the analysis, including volumetric flow rate, slippage, shaft power, volumetric efficiency, and system efficiency. The results show that the pressure and speed distribution in the pump chamber of the PCP is relatively homogenous under different working conditions, whereas the pressure and speed exhibited sharp changes at the stator and rotor sealing line and adjacent areas in the pump chamber. Increasing the viscosity of the oil and the speed of the rotor can effectively improve the flow characteristics of the PCP, but extremely high pump rotation speed would cause a decline in system efficiency. Increasing the differential pressure and the void fraction of oil would result in a decrease in the volumetric flow rate and efficiency of the PCP. Considering the variation law of the PCP's performance parameters, the optimal interval for each operating parameter of the PCP is as follows: Oil viscosity at 50–100 mPa·s, pump rotation speed at 200–300 rev/min, differential pressure at 0.2–0.3 MPa, and the void fraction of oil not more than 50%. This research can provide technical support for the optimization of the working conditions of the PCP on site.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46031747","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Zargar, M. Johns, Jana M. Aljindan, M. Noui-Mehidi, K. O'Neill
Multiphase flowmetering is a requirement across a range of process industries, particularly those that pertain to oil and gas. Generally, both the composition and individual phase velocities are required; this results in a complex measurement task made more acute by the prevalence of turbulent flow and a variety of flow regimes. In the current review, the main technical options to meet this metrology are outlined and used to provide context for the main focus on the use of nuclear magnetic resonance (NMR) technology for multiphase flowmetering. Relevant fundamentals of NMR are detailed as is their exploitation to quantify flow composition and individual phase velocities for multiphase flow. The review then proceeds to detail three NMR multiphase flowmeter (MPFM) apparatus and concludes with a consideration of future challenges and prospects for the technology.
{"title":"Nuclear Magnetic Resonance Multiphase Flowmeters: Current Status and Future Prospects","authors":"M. Zargar, M. Johns, Jana M. Aljindan, M. Noui-Mehidi, K. O'Neill","doi":"10.2118/205351-PA","DOIUrl":"https://doi.org/10.2118/205351-PA","url":null,"abstract":"\u0000 Multiphase flowmetering is a requirement across a range of process industries, particularly those that pertain to oil and gas. Generally, both the composition and individual phase velocities are required; this results in a complex measurement task made more acute by the prevalence of turbulent flow and a variety of flow regimes. In the current review, the main technical options to meet this metrology are outlined and used to provide context for the main focus on the use of nuclear magnetic resonance (NMR) technology for multiphase flowmetering. Relevant fundamentals of NMR are detailed as is their exploitation to quantify flow composition and individual phase velocities for multiphase flow. The review then proceeds to detail three NMR multiphase flowmeter (MPFM) apparatus and concludes with a consideration of future challenges and prospects for the technology.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49420633","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The litmus test for downhole multiphase flowmeters is to compare the measured phase flow rates with the rates from a test separator or other surface measurement systems. In most cases, the composition of the measurand is required for flowmeters. This is typically obtained from bottomhole fluid samples. Extracting and analyzing fluid samples is an expensive process mostly done at the initial stages of field development. In some cases, the composition may be old or unavailable, leading to subpar flowmeter performance compared to surface systems. In this work, it is shown that when the data from a surface system such as a test separator are used in conjunction with the mixture sound speed measured downhole, it is possible to optimize a downhole multiphase flowmeter system without obtaining new fluid samples. The optimization process is independent of the downhole measurement device because the required flow-velocity and sound-speed measurements may be obtained from separate devices. For example, the fluid bulk velocity and mixture sound speed can be measured by a local measurement device and a distributed acoustic sensing (DAS) system, respectively. The main challenge in a flow-velocity/sound-speed measurement system is determining individual phase sound speeds so that the mixture phase fraction can be correctly determined using Wood’s mixture sound speed model. The phase fraction from the separator tests can be used as the target value to optimize the performance of the system. The system has two operation modes. In optimization mode, the individual phase sound speeds are calculated backward using the predicted phase fractions from surface measurements. Pressure and temperature variations at measurement locations, as well as pipe compliance effects, are accounted for during the process. After the adjustment of individual phase sound speeds, steady-state operation mode takes over, and a forward calculation is implemented using the same model. The final phase fraction agrees well with the actual value and can be improved further with an iterative approach. This novel method is demonstrated in a North Sea case history. A downhole optical flowmeter in a North Sea field measured mixture velocity and sound speed. Well-test results indicated that water cut from the flowmeter was underreported and phase flow rates did not match test-separator rates. Instead of halting production and going through a fluid sample analysis cycle, the test-separator water cut was used as the target value to optimize oil phase sound speed using Wood’s model in the optimization mode. The difference between the initial and optimized oil sound speeds was extrapolated to other pressure and temperature conditions, and steady-state operation mode showed that separator tests and flowmeter measurements closely matched. Subsequent flowmeter and test-separator data confirmed excellent agreement. Using surface measurements and downhole mixture sound speed to optimize phase flow rates is
{"title":"Flow Measurement Optimization Using Surface Measurements and Downhole Sound Speed Measurements from Local or Distributed Acoustic Sensors","authors":"O. Unalmis","doi":"10.2118/201313-PA","DOIUrl":"https://doi.org/10.2118/201313-PA","url":null,"abstract":"\u0000 The litmus test for downhole multiphase flowmeters is to compare the measured phase flow rates with the rates from a test separator or other surface measurement systems. In most cases, the composition of the measurand is required for flowmeters. This is typically obtained from bottomhole fluid samples. Extracting and analyzing fluid samples is an expensive process mostly done at the initial stages of field development. In some cases, the composition may be old or unavailable, leading to subpar flowmeter performance compared to surface systems. In this work, it is shown that when the data from a surface system such as a test separator are used in conjunction with the mixture sound speed measured downhole, it is possible to optimize a downhole multiphase flowmeter system without obtaining new fluid samples. The optimization process is independent of the downhole measurement device because the required flow-velocity and sound-speed measurements may be obtained from separate devices. For example, the fluid bulk velocity and mixture sound speed can be measured by a local measurement device and a distributed acoustic sensing (DAS) system, respectively. The main challenge in a flow-velocity/sound-speed measurement system is determining individual phase sound speeds so that the mixture phase fraction can be correctly determined using Wood’s mixture sound speed model. The phase fraction from the separator tests can be used as the target value to optimize the performance of the system. The system has two operation modes. In optimization mode, the individual phase sound speeds are calculated backward using the predicted phase fractions from surface measurements. Pressure and temperature variations at measurement locations, as well as pipe compliance effects, are accounted for during the process. After the adjustment of individual phase sound speeds, steady-state operation mode takes over, and a forward calculation is implemented using the same model. The final phase fraction agrees well with the actual value and can be improved further with an iterative approach. This novel method is demonstrated in a North Sea case history. A downhole optical flowmeter in a North Sea field measured mixture velocity and sound speed. Well-test results indicated that water cut from the flowmeter was underreported and phase flow rates did not match test-separator rates. Instead of halting production and going through a fluid sample analysis cycle, the test-separator water cut was used as the target value to optimize oil phase sound speed using Wood’s model in the optimization mode. The difference between the initial and optimized oil sound speeds was extrapolated to other pressure and temperature conditions, and steady-state operation mode showed that separator tests and flowmeter measurements closely matched. Subsequent flowmeter and test-separator data confirmed excellent agreement. Using surface measurements and downhole mixture sound speed to optimize phase flow rates is","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48018913","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shreyas V. Jalikop, B. Scheichl, S. Eder, S. Hönig
Artificial lift systems are widely used in oil production, of which sucker rod pumps are conceptually among the simpler ones. The reciprocating movement of the plunger triggers the opening and closing of two ball valves, allowing fluid to be pumped to the surface. Their built-in ball valves are subject to long-time erosion and fail as a consequence of this damage mechanism. Understanding the principal damage mechanisms requires a thorough examination of the fluid dynamics during the opening and closing action of these valves. In this article, we present a fluid-structure interaction model that simultaneously computes the fluid flow in the traveling valve (TV), the standing valve (SV), and the chamber of sucker rod pumps during a full pump cycle. The simulations shed light on the causes of valve damage for standard and nonideal operating conditions of the pump. In particular, our simulations based on real pump operating envelopes reveal that the so-called “midcycle valve closure” is likely to occur. Such additional closing and opening events of the valves multiply situations in which the flow conditions are harmful to the individual pump components, leading to efficiency reduction and pump failure. This mechanism, hitherto unreported in the literature, is believed to constitute the primary cause of long-term valve damage. Our finite element method-based computational-fluid-dynamics model can accurately describe the opening and closing cycles of the two valves. For the first time, this approach allows an analysis of real TV speed versus position plots, usually called pump cards. The effects of stroke length, plunger speed, and fluid parameters on the velocity and pressure at any point and time inside the pump can thus be investigated. Identifying the damage-critical flow parameters can help suggest measures to avoid unfavorable operating envelopes in future pump designs. Our flow model may support field operations throughout the entire well life, ranging from improved downhole pump design to optimized pump operation or material selections. It can aid the creation of an ideal interaction between the valves, thus avoiding midcycle valve closure to drastically extend the mean time between failures of sucker rod pumps. Finally, our simulation approach will speed up new pump component development while greatly reducing the necessity for costly laboratory testing.
{"title":"A New Computational Fluid Dynamics Model To Optimize Sucker Rod Pump Operation and Design","authors":"Shreyas V. Jalikop, B. Scheichl, S. Eder, S. Hönig","doi":"10.2118/201285-PA","DOIUrl":"https://doi.org/10.2118/201285-PA","url":null,"abstract":"\u0000 Artificial lift systems are widely used in oil production, of which sucker rod pumps are conceptually among the simpler ones. The reciprocating movement of the plunger triggers the opening and closing of two ball valves, allowing fluid to be pumped to the surface. Their built-in ball valves are subject to long-time erosion and fail as a consequence of this damage mechanism. Understanding the principal damage mechanisms requires a thorough examination of the fluid dynamics during the opening and closing action of these valves.\u0000 In this article, we present a fluid-structure interaction model that simultaneously computes the fluid flow in the traveling valve (TV), the standing valve (SV), and the chamber of sucker rod pumps during a full pump cycle. The simulations shed light on the causes of valve damage for standard and nonideal operating conditions of the pump. In particular, our simulations based on real pump operating envelopes reveal that the so-called “midcycle valve closure” is likely to occur. Such additional closing and opening events of the valves multiply situations in which the flow conditions are harmful to the individual pump components, leading to efficiency reduction and pump failure. This mechanism, hitherto unreported in the literature, is believed to constitute the primary cause of long-term valve damage.\u0000 Our finite element method-based computational-fluid-dynamics model can accurately describe the opening and closing cycles of the two valves. For the first time, this approach allows an analysis of real TV speed versus position plots, usually called pump cards. The effects of stroke length, plunger speed, and fluid parameters on the velocity and pressure at any point and time inside the pump can thus be investigated. Identifying the damage-critical flow parameters can help suggest measures to avoid unfavorable operating envelopes in future pump designs.\u0000 Our flow model may support field operations throughout the entire well life, ranging from improved downhole pump design to optimized pump operation or material selections. It can aid the creation of an ideal interaction between the valves, thus avoiding midcycle valve closure to drastically extend the mean time between failures of sucker rod pumps. Finally, our simulation approach will speed up new pump component development while greatly reducing the necessity for costly laboratory testing.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49206752","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Smart completions enable physical measurements over space and time, which provides large volumes of information at unprecedented rates. However, optimizing inflow control valve (ICV) settings of smart multilateral wells is a challenging task. Traditionally, ICV field tests, evaluating well performance at different ICV settings, are conducted to observe flow behavior and configure ICVs; however, this is often suboptimal. This study investigated a surrogate-based optimization algorithm that minimizes the number of ICV field tests required, predicts well performance of all unseen combination of ICV settings, and determines the optimal ICV setting and net present value (NPV). A numerical model of a real offshore field in Saudi Arabia was used to generate scenarios involving a two-phase (oil and water) reservoir with trilateral producers. Multiple scenarios were examined with variations in design parameters, mainly well count, placement, and configuration. Eight discrete settings were assumed to match the commonly installed ICV technology, where all possible scenarios were simulated to establish ground truth. The investigation considered three major algorithmic components: sampling, machine learning, and optimization. The sampling strategy compared physics-based initialization, space-filling sampling, and triangulation-based adaptive sampling. A cross-validated neural network was used to fit a surrogate (in this case, machine learning algorithm) dynamically, whereas enumeration was adopted for optimization to avoid errors arising from using common optimizers. This study evaluated two sampling techniques: space-filling and adaptive sampling. The latter was found superior in capturing reservoir behavior with the smallest number of simulation runs (i.e., ICV field tests). Algorithm performance was evaluated based on the number of ICV field tests required to exceed an R2 threshold of 90% on all unseen scenarios and match the optimal ICV settings and NPV. Surface and downhole flow profile prediction and optimization were achieved successfully using this approach. To determine the diminishing value of additional ICV field tests, the triangulation sampling loss was used as a stoppage criterion. When running the algorithm on a single producer for both surface and downhole oil and water flow prediction, the algorithm required only 6 and 11 ICV field tests to achieve 80% and 90% R2 across the different cases of this real reservoir model. Fishbone wellbore configurations were found to pose a more challenging task because changes in any ICV pressure decrease affects multiple laterals simultaneously, which increases the level of interdependence. The resultant surrogate was used to decide on the optimal settings of ICV devices and effectively predict the NPV. Surrogates, in this approach, are statistical proxies of the targeted ground-truth production function. Further improvement was accomplished through adaptively sampling and fitting surrogates to predict NP
{"title":"Surrogate-Based Prediction and Optimization of Multilateral Inflow Control Valve Flow Performance with Production Data","authors":"M. Aljubran, R. Horne","doi":"10.2118/200884-pa","DOIUrl":"https://doi.org/10.2118/200884-pa","url":null,"abstract":"\u0000 Smart completions enable physical measurements over space and time, which provides large volumes of information at unprecedented rates. However, optimizing inflow control valve (ICV) settings of smart multilateral wells is a challenging task. Traditionally, ICV field tests, evaluating well performance at different ICV settings, are conducted to observe flow behavior and configure ICVs; however, this is often suboptimal. This study investigated a surrogate-based optimization algorithm that minimizes the number of ICV field tests required, predicts well performance of all unseen combination of ICV settings, and determines the optimal ICV setting and net present value (NPV).\u0000 A numerical model of a real offshore field in Saudi Arabia was used to generate scenarios involving a two-phase (oil and water) reservoir with trilateral producers. Multiple scenarios were examined with variations in design parameters, mainly well count, placement, and configuration. Eight discrete settings were assumed to match the commonly installed ICV technology, where all possible scenarios were simulated to establish ground truth. The investigation considered three major algorithmic components: sampling, machine learning, and optimization. The sampling strategy compared physics-based initialization, space-filling sampling, and triangulation-based adaptive sampling. A cross-validated neural network was used to fit a surrogate (in this case, machine learning algorithm) dynamically, whereas enumeration was adopted for optimization to avoid errors arising from using common optimizers.\u0000 This study evaluated two sampling techniques: space-filling and adaptive sampling. The latter was found superior in capturing reservoir behavior with the smallest number of simulation runs (i.e., ICV field tests). Algorithm performance was evaluated based on the number of ICV field tests required to exceed an R2 threshold of 90% on all unseen scenarios and match the optimal ICV settings and NPV. Surface and downhole flow profile prediction and optimization were achieved successfully using this approach. To determine the diminishing value of additional ICV field tests, the triangulation sampling loss was used as a stoppage criterion. When running the algorithm on a single producer for both surface and downhole oil and water flow prediction, the algorithm required only 6 and 11 ICV field tests to achieve 80% and 90% R2 across the different cases of this real reservoir model. Fishbone wellbore configurations were found to pose a more challenging task because changes in any ICV pressure decrease affects multiple laterals simultaneously, which increases the level of interdependence. The resultant surrogate was used to decide on the optimal settings of ICV devices and effectively predict the NPV. Surrogates, in this approach, are statistical proxies of the targeted ground-truth production function. Further improvement was accomplished through adaptively sampling and fitting surrogates to predict NP","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-02-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200884-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46970538","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Kurniawan S. Suminar, I. Gavrielatos, Ramin Dabirian, R. Mohan, O. Shoham
An experimental and theoretical investigation of surfactant-stabilized oil/water emulsion characteristics was carried out under water sweep (WS) and oil sweep (OS) conditions. Both hydrophilic and hydrophobic surfactants were used, with concentrations less than and more than the critical micelle concentration (CMC). Experimental data were acquired for detection of the phase-inversion region, which was measured simultaneously by several independent methods. These include a circular differential dielectric sensor (C-DDS), a rectangular differential dielectric sensor (R-DDS) (both sensors accurately detect the phase-inversion region), a pressure transducer, and a mass flowmeter. The addition of an emulsifier surfactant to an oil/water mixture generated a stable emulsion, which resulted in a phase-inversion delay. For water-continuous to oil-continuous flow, a hydrophilic surfactant was a better emulsifier, while for oil-continuous to water-continuous flow, a hydrophobic surfactant was a better emulsifier for creating more stable emulsions. The surfactant/oil/water emulsion resulted in an increase of the dispersed-phase volume fraction required for phase inversion, as compared to the case of oil/water dispersions without surfactant. For emulsions with surfactant concentrations above CMC, the presence of micelles contributed to further delay of the phase inversion, as compared to those with surfactant concentrations below CMC. The phase-inversion region exhibits a hysteresis between the OS and WS runs, below CMC and above CMC, which was due to the difference in droplet sizes caused by different breakup and coalescence processes for oil-continuous and water-continuous flow. This research shows that the DDS is an efficient instrumentation that can be used to detect the region where the emulsion phase inversion is expected to occur. Moreover, the experimental results and the pertinent analysis and discussion provide useful insights for a more informed design of surface facilities (including emulsion separators) in oil and gas production operations.
{"title":"Detecting Phase-Inversion Region of Surfactant-Stabilized Oil/Water Emulsions Using Differential Dielectric Sensors","authors":"Kurniawan S. Suminar, I. Gavrielatos, Ramin Dabirian, R. Mohan, O. Shoham","doi":"10.2118/205018-PA","DOIUrl":"https://doi.org/10.2118/205018-PA","url":null,"abstract":"\u0000 An experimental and theoretical investigation of surfactant-stabilized oil/water emulsion characteristics was carried out under water sweep (WS) and oil sweep (OS) conditions. Both hydrophilic and hydrophobic surfactants were used, with concentrations less than and more than the critical micelle concentration (CMC). Experimental data were acquired for detection of the phase-inversion region, which was measured simultaneously by several independent methods. These include a circular differential dielectric sensor (C-DDS), a rectangular differential dielectric sensor (R-DDS) (both sensors accurately detect the phase-inversion region), a pressure transducer, and a mass flowmeter.\u0000 The addition of an emulsifier surfactant to an oil/water mixture generated a stable emulsion, which resulted in a phase-inversion delay. For water-continuous to oil-continuous flow, a hydrophilic surfactant was a better emulsifier, while for oil-continuous to water-continuous flow, a hydrophobic surfactant was a better emulsifier for creating more stable emulsions.\u0000 The surfactant/oil/water emulsion resulted in an increase of the dispersed-phase volume fraction required for phase inversion, as compared to the case of oil/water dispersions without surfactant. For emulsions with surfactant concentrations above CMC, the presence of micelles contributed to further delay of the phase inversion, as compared to those with surfactant concentrations below CMC. The phase-inversion region exhibits a hysteresis between the OS and WS runs, below CMC and above CMC, which was due to the difference in droplet sizes caused by different breakup and coalescence processes for oil-continuous and water-continuous flow.\u0000 This research shows that the DDS is an efficient instrumentation that can be used to detect the region where the emulsion phase inversion is expected to occur. Moreover, the experimental results and the pertinent analysis and discussion provide useful insights for a more informed design of surface facilities (including emulsion separators) in oil and gas production operations.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43298662","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T. Husveg, R. Husveg, Niels van Teeffelen, R. Verwey, Peter Guinee
In hydrocarbon production and processing, choke and control valves mix and emulsify petroleum phases. The consequence is often that the efficiency of separation processes is affected and finally that the quality of oil and water phases is degraded. Over the last few years, low-shear valves targeting petroleum processes have emerged on the market. This paper presents four separate live-fluid experiences from low-shear valve installations, each surveyed and documented by an independent third party. Three of the installations refer to choke valves, whereas the fourth installation refers to a control valve. For each installation, standard choke and control valves were used as reference valves. In terms of downstream separation efficiency, the low-shear choke valves reduced oil-in-water concentrations respectively by 70, 45, and 60%, by total average. In the control valve application, the low-shear valve, which was located between the hydrocyclones and a compact flotation unit, reduced the oil-in-water concentration by 23%. In sum, the field installations have demonstrated that low-shear valves significantly and consistently reduce oil-in-water concentrations and thus improve the produced water quality. The results signify that low-shear valves may be used in debottlenecking separation and produced water treatment processes, reducing the environmental influence from produced water discharges. Because the low-shear technology enables processing of petroleum phases with less effort, energy, and chemicals, it also reduces emissions to air.
{"title":"Reviewing Cyclonic Low-Shear Choke and Control Valve Field Experiences","authors":"T. Husveg, R. Husveg, Niels van Teeffelen, R. Verwey, Peter Guinee","doi":"10.2118/205016-PA","DOIUrl":"https://doi.org/10.2118/205016-PA","url":null,"abstract":"\u0000 In hydrocarbon production and processing, choke and control valves mix and emulsify petroleum phases. The consequence is often that the efficiency of separation processes is affected and finally that the quality of oil and water phases is degraded. Over the last few years, low-shear valves targeting petroleum processes have emerged on the market.\u0000 This paper presents four separate live-fluid experiences from low-shear valve installations, each surveyed and documented by an independent third party. Three of the installations refer to choke valves, whereas the fourth installation refers to a control valve. For each installation, standard choke and control valves were used as reference valves. In terms of downstream separation efficiency, the low-shear choke valves reduced oil-in-water concentrations respectively by 70, 45, and 60%, by total average. In the control valve application, the low-shear valve, which was located between the hydrocyclones and a compact flotation unit, reduced the oil-in-water concentration by 23%.\u0000 In sum, the field installations have demonstrated that low-shear valves significantly and consistently reduce oil-in-water concentrations and thus improve the produced water quality. The results signify that low-shear valves may be used in debottlenecking separation and produced water treatment processes, reducing the environmental influence from produced water discharges. Because the low-shear technology enables processing of petroleum phases with less effort, energy, and chemicals, it also reduces emissions to air.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45780144","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Accurate zonal flow rate determination is necessary for better reservoir behavior understanding and for making important decisions that can improve well productivity. Knowledge of the capabilities of different reservoir zones in the same well also has significant importance in reservoir performance monitoring and selection of perforation intervals in development wells. Conventional production log analysis techniques can usually yield good results only if the fullbore spinner readings are reliable. However, the fullbore spinner measurement may not be available in some wells. Examples include cases in which the fullbore spinner cannot access the well due to mechanical obstruction, or when the casing is not clean enough, causing potential plugging of fullbore spinner blades. In these situations, the fullbore flow-rate readings may not be available or at least unclear or confusing, which may lead to incorrect decisions. In many of these situations, inline spinner (ILS) data may be readily available. The ILS is often used for qualitative interpretation (i.e., determining which zones are producing), but there is not a specific method to use the ILS for a quantitative solution in the absence of surface measurements of rates. In this paper, we introduce a new method to calculate the volumetric zonal flow rate using ILS data with high accuracy. Approximately 40 oil wells are used to develop an empirical correlation to compute zonal flow rates from ILS data in casing strings. The new method was used to quantitatively interpret eight oil wells for validation. In these wells, fullbore and ILS data were significantly different. The new method for interpretation of ILS data provided results consistent with surface production tests and led to decisions that contributed to increasing production rates.
{"title":"Use of Inline Spinner for Determination of Zonal Flow Rates in Vertical and Moderately Deviated Wells","authors":"M. El-Sheikh, Ahmed H. El-Banbi","doi":"10.2118/205021-PA","DOIUrl":"https://doi.org/10.2118/205021-PA","url":null,"abstract":"\u0000 Accurate zonal flow rate determination is necessary for better reservoir behavior understanding and for making important decisions that can improve well productivity. Knowledge of the capabilities of different reservoir zones in the same well also has significant importance in reservoir performance monitoring and selection of perforation intervals in development wells.\u0000 Conventional production log analysis techniques can usually yield good results only if the fullbore spinner readings are reliable. However, the fullbore spinner measurement may not be available in some wells. Examples include cases in which the fullbore spinner cannot access the well due to mechanical obstruction, or when the casing is not clean enough, causing potential plugging of fullbore spinner blades. In these situations, the fullbore flow-rate readings may not be available or at least unclear or confusing, which may lead to incorrect decisions. In many of these situations, inline spinner (ILS) data may be readily available.\u0000 The ILS is often used for qualitative interpretation (i.e., determining which zones are producing), but there is not a specific method to use the ILS for a quantitative solution in the absence of surface measurements of rates. In this paper, we introduce a new method to calculate the volumetric zonal flow rate using ILS data with high accuracy. Approximately 40 oil wells are used to develop an empirical correlation to compute zonal flow rates from ILS data in casing strings. The new method was used to quantitatively interpret eight oil wells for validation. In these wells, fullbore and ILS data were significantly different. The new method for interpretation of ILS data provided results consistent with surface production tests and led to decisions that contributed to increasing production rates.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43180091","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T. Ahmed, P. Russell, F. Hamad, S. Gooneratne, N. Makwashi
In the first part of this work, the development of a capital cost optimization model for sizing three-phase separators was described. The developed model uses generalized reduced gradient nonlinear algorithms to determine the minimum cost associated with the construction of horizontal separators subject to four sets of constraints. In the second part, an experimental test rig was designed and used to investigate the effect of gas flow rate, liquid flow rate, and slenderness ratio (L/D) on the separation performance of horizontal three-phase separators. The results indicated an inverse relationship between an increase in gas and liquid flow rate and the separator outlet quality. It also indicated a direct relationship between an increase in slenderness ratio and separator outlet quality. The results also showed that the gradient change of the percentage of water in the oil outlet with respect to slenderness ratio decreased to ratios of 6:1. Hence, the separation rate increased. At ratios greater than 6:1, the separation still increases, but the gradient change in separation drops off, implying that the benefit in terms of separation is diminishing beyond this point. Therefore, the optimal slenderness ratio for technical reasons is 6:1.
{"title":"The Effects of Inlet Flow Rates and Slenderness Ratio on the Separation Performance of a Horizontal Three-Phase Separator","authors":"T. Ahmed, P. Russell, F. Hamad, S. Gooneratne, N. Makwashi","doi":"10.2118/205517-pa","DOIUrl":"https://doi.org/10.2118/205517-pa","url":null,"abstract":"\u0000 In the first part of this work, the development of a capital cost optimization model for sizing three-phase separators was described. The developed model uses generalized reduced gradient nonlinear algorithms to determine the minimum cost associated with the construction of horizontal separators subject to four sets of constraints. In the second part, an experimental test rig was designed and used to investigate the effect of gas flow rate, liquid flow rate, and slenderness ratio (L/D) on the separation performance of horizontal three-phase separators. The results indicated an inverse relationship between an increase in gas and liquid flow rate and the separator outlet quality. It also indicated a direct relationship between an increase in slenderness ratio and separator outlet quality. The results also showed that the gradient change of the percentage of water in the oil outlet with respect to slenderness ratio decreased to ratios of 6:1. Hence, the separation rate increased. At ratios greater than 6:1, the separation still increases, but the gradient change in separation drops off, implying that the benefit in terms of separation is diminishing beyond this point. Therefore, the optimal slenderness ratio for technical reasons is 6:1.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44828550","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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