Tao Zhang, Ming Li, Jianchun Guo, Haoran Gou, Kefan Mu
The temporary plugging by particles in the wellbore can open new perforation clusters and increase stimulated reservoir volume, but the temporary plugging process of particles is not clear. Therefore, in this paper, we take an ultradeep well in the Tarim Basin as the research object and establish a numerical model based on the coupled computational fluid dynamics-discrete element technology (CFD-DEM) approach, which accurately describes the movement process and mechanism of the temporary plugging particles in the wellbore. Furthermore, the influence of flow rate, concentration of injected particles, and the injected mass ratio of particle size on the temporary plugging effect were studied, respectively. In addition, based on the results of the orthogonal experimental analysis, we obtained the pump rate as the primary factor affecting the effect of temporary plugging, and we recommended the optimal operation parameters for temporary plugging by particles in the field: The pump rate is 2 m3/min, the concentration of the injected temporary plugging particles is 20%, and the ratio of the mass of the injected temporary plugging particles with particle size 1 to 5 mm to the mass of the temporary plugging particles with particle size 5 to 10 mm is 3:1. Finally, a single well that had implemented temporary plugging by particles was used to verify the recommended optimal temporary plugging operation parameters. The research results of this paper provide important guidance and suggestions for the design of temporary plugging schemes on the field.
{"title":"Numerical Study on Mechanism and Parameters Optimization of Temporary Plugging by Particles in Wellbore","authors":"Tao Zhang, Ming Li, Jianchun Guo, Haoran Gou, Kefan Mu","doi":"10.2118/208585-pa","DOIUrl":"https://doi.org/10.2118/208585-pa","url":null,"abstract":"\u0000 The temporary plugging by particles in the wellbore can open new perforation clusters and increase stimulated reservoir volume, but the temporary plugging process of particles is not clear. Therefore, in this paper, we take an ultradeep well in the Tarim Basin as the research object and establish a numerical model based on the coupled computational fluid dynamics-discrete element technology (CFD-DEM) approach, which accurately describes the movement process and mechanism of the temporary plugging particles in the wellbore. Furthermore, the influence of flow rate, concentration of injected particles, and the injected mass ratio of particle size on the temporary plugging effect were studied, respectively. In addition, based on the results of the orthogonal experimental analysis, we obtained the pump rate as the primary factor affecting the effect of temporary plugging, and we recommended the optimal operation parameters for temporary plugging by particles in the field: The pump rate is 2 m3/min, the concentration of the injected temporary plugging particles is 20%, and the ratio of the mass of the injected temporary plugging particles with particle size 1 to 5 mm to the mass of the temporary plugging particles with particle size 5 to 10 mm is 3:1. Finally, a single well that had implemented temporary plugging by particles was used to verify the recommended optimal temporary plugging operation parameters. The research results of this paper provide important guidance and suggestions for the design of temporary plugging schemes on the field.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49162570","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}
Zhihui Wang, X. Zhang, Ruiquan Liao, Yu Lei, Z. Fang
The vane swirler separator is widely used in the separation process of wet natural gas owing to a small volume, high efficiency, economy, and environmental protection. In addition to the separation efficiency, the pressure drop is also an important technical and operational index for evaluating the performance of the swirler. In this study, the pressure drop of a swirler vane separator was studied through laboratory experiments and numerical simulations. Through the visualization experimental study of the liquid membrane formation rule and its movement pattern, the reduced gas velocity on the pressure drop was divided into three stages. For a gas superficial velocity less than 5.69 m/s, the effect of gas superficial velocity on the pressure drop was small; for a gas superficial velocity greater than 16.57 m/s, the pressure drop increased significantly with an increase in gas flow rate, and the maximum pressure drop was generated by the two-stage swirler, downstream of which the pressure decreased precipitously. We also observed that when the liquid volume content was less than 3%, the gas superficial velocity was the dominant factor affecting the change in the pressure drop. The average relative error of the pressure drop prediction model based on the conservation of the energy law was 6.16%, which indicated a high calculation accuracy.
{"title":"Study on Pressure Drop Characteristics of a Two-Stage Swirler Separator","authors":"Zhihui Wang, X. Zhang, Ruiquan Liao, Yu Lei, Z. Fang","doi":"10.2118/208592-pa","DOIUrl":"https://doi.org/10.2118/208592-pa","url":null,"abstract":"\u0000 The vane swirler separator is widely used in the separation process of wet natural gas owing to a small volume, high efficiency, economy, and environmental protection. In addition to the separation efficiency, the pressure drop is also an important technical and operational index for evaluating the performance of the swirler. In this study, the pressure drop of a swirler vane separator was studied through laboratory experiments and numerical simulations. Through the visualization experimental study of the liquid membrane formation rule and its movement pattern, the reduced gas velocity on the pressure drop was divided into three stages. For a gas superficial velocity less than 5.69 m/s, the effect of gas superficial velocity on the pressure drop was small; for a gas superficial velocity greater than 16.57 m/s, the pressure drop increased significantly with an increase in gas flow rate, and the maximum pressure drop was generated by the two-stage swirler, downstream of which the pressure decreased precipitously. We also observed that when the liquid volume content was less than 3%, the gas superficial velocity was the dominant factor affecting the change in the pressure drop. The average relative error of the pressure drop prediction model based on the conservation of the energy law was 6.16%, which indicated a high calculation accuracy.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46505160","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}
Xinghui Liu, Jiehao Wang, Amit Singh, M. Rijken, Dean Wehunt, Larry Chrusch, Faraj A. Ahmad, J. Miskimins
Multistage plug-and-perforate fracturing of horizontal wells has proved to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement in all perforation clusters is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each fracturing stage by means of a computational fluid dynamics (CFD) modeling approach. A laboratory-scale CFD model was built and calibrated using experimental data of proppant transport through horizontal pipes available from several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation variables (orientation, size, and number), cluster variables (count and spacing), fluid properties, proppant properties, pumping rates, and stress shadow effects. Both laboratory and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations because of gravitational effects. Laboratory and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation/cluster variables and other treatment design factors. CFD modeling plays an important role in this design-optimizationprocess.
{"title":"Achieving Near-Uniform Fluid and Proppant Placement in Multistage Fractured Horizontal Wells: A Computational Fluid Dynamics Modeling Approach","authors":"Xinghui Liu, Jiehao Wang, Amit Singh, M. Rijken, Dean Wehunt, Larry Chrusch, Faraj A. Ahmad, J. Miskimins","doi":"10.2118/204182-pa","DOIUrl":"https://doi.org/10.2118/204182-pa","url":null,"abstract":"\u0000 Multistage plug-and-perforate fracturing of horizontal wells has proved to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement in all perforation clusters is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each fracturing stage by means of a computational fluid dynamics (CFD) modeling approach.\u0000 A laboratory-scale CFD model was built and calibrated using experimental data of proppant transport through horizontal pipes available from several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation variables (orientation, size, and number), cluster variables (count and spacing), fluid properties, proppant properties, pumping rates, and stress shadow effects.\u0000 Both laboratory and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations because of gravitational effects. Laboratory and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation/cluster variables and other treatment design factors. CFD modeling plays an important role in this design-optimizationprocess.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41420942","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}
During the years 2017–2020, when Iran faced restrictions on the sale of oil and gas condensate and due to the need for domestic consumption and gas sales commitments, it was inevitable to produce gas at full capacity. This coercion has led to significant production of gas condensates. Some of these condensates were sold, some were converted into products such as gasoline in domestic refineries, and some of these condensates needed to be stored, but the storage capacity was limited. For the purpose of underground condensate storage, a heavy oil reservoir was selected based on some technical and operational criteria. A feasibility study was conducted to evaluate the potential risks of condensate injection into the reservoir. The results of tests on asphaltene precipitation, as the most important risk, indicated no severe precipitation would occur even if high concentration of condensate mixed with the reservoir heavy oil. The recovery of condensate and the production performance of the reservoir were simulated in three different injection-production scenarios. The results showed a positive effect of condensate injection on production rate of the reservoir. Moreover, satisfactory volume of condensate could be recovered in a reasonable period of time.
{"title":"Compatibility Study of Condensate and Heavy Oil for Storage in an Iranian Reservoir","authors":"K. Zobeidi, M. Ganjeh-Ghazvini, V. Hematfar","doi":"10.2118/206731-pa","DOIUrl":"https://doi.org/10.2118/206731-pa","url":null,"abstract":"\u0000 During the years 2017–2020, when Iran faced restrictions on the sale of oil and gas condensate and due to the need for domestic consumption and gas sales commitments, it was inevitable to produce gas at full capacity. This coercion has led to significant production of gas condensates. Some of these condensates were sold, some were converted into products such as gasoline in domestic refineries, and some of these condensates needed to be stored, but the storage capacity was limited. For the purpose of underground condensate storage, a heavy oil reservoir was selected based on some technical and operational criteria. A feasibility study was conducted to evaluate the potential risks of condensate injection into the reservoir. The results of tests on asphaltene precipitation, as the most important risk, indicated no severe precipitation would occur even if high concentration of condensate mixed with the reservoir heavy oil. The recovery of condensate and the production performance of the reservoir were simulated in three different injection-production scenarios. The results showed a positive effect of condensate injection on production rate of the reservoir. Moreover, satisfactory volume of condensate could be recovered in a reasonable period of time.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44086748","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 impacts of formation layering on hydraulic fracture containment and on pumping energy are critical factors in a successful stimulation treatment. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young’s moduli. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in the field (Warpinski et al. 1998). Enhanced toughness, in-situ stress, interface slip, and energy dissipation in the layered rocks should be combined to contribute to the fracture containment analysis. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on the finite element method. We use laboratory and numerical simulations to investigate these factors and how they affect hydraulic fracture propagation, height growth, and injection pressure. The 3D fully coupled hydromechanical model uses a special zero-thickness interface element and the cohesive zone model (CZM) to simulate fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydromechanical model has been verified successfully through benchmarked analytical solutions. The influence of layered Young’s modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are simulated explicitly through the use of the hydromechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on hydraulic fracture propagation are studied. Hydraulic fractures tend to propagate in the layer with lower Young’s modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Contrary to the conventional view, the location of hydraulic fracturing (in softer vs. stiffer layers) does affect fracture geometry evolution. In addition, depending on the mechanical properties and the conductivity of the interfaces, the shear slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces can serve as an effective mechanism of containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the layers’ mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the re
{"title":"The Impact of Layering and Permeable Frictional Interfaces on Hydraulic Fracturing in Unconventional Reservoirs","authors":"Q. Gao, A. Ghassemi","doi":"10.2118/195881-pa","DOIUrl":"https://doi.org/10.2118/195881-pa","url":null,"abstract":"\u0000 The impacts of formation layering on hydraulic fracture containment and on pumping energy are critical factors in a successful stimulation treatment. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young’s moduli. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in the field (Warpinski et al. 1998). Enhanced toughness, in-situ stress, interface slip, and energy dissipation in the layered rocks should be combined to contribute to the fracture containment analysis. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on the finite element method. We use laboratory and numerical simulations to investigate these factors and how they affect hydraulic fracture propagation, height growth, and injection pressure.\u0000 The 3D fully coupled hydromechanical model uses a special zero-thickness interface element and the cohesive zone model (CZM) to simulate fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydromechanical model has been verified successfully through benchmarked analytical solutions. The influence of layered Young’s modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are simulated explicitly through the use of the hydromechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on hydraulic fracture propagation are studied.\u0000 Hydraulic fractures tend to propagate in the layer with lower Young’s modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Contrary to the conventional view, the location of hydraulic fracturing (in softer vs. stiffer layers) does affect fracture geometry evolution. In addition, depending on the mechanical properties and the conductivity of the interfaces, the shear slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces can serve as an effective mechanism of containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the layers’ mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the re","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42071864","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. Ganat, M. Hrairi, R. Gholami, Taha Abouargub, E. Motaei
Liquid-liquid phase flow in pipes merits further investigation as a challenging issue that has very rich physics and is faced in everyday applications. It is the main problem challenging the fluid flow mechanism in the oil and gas industry. The pressure gradient of liquid flow and flow pattern are still the topics of numerous research projects. In this paper, the emphasis is on further investigation to research the flow pattern, water holdup (HW), and pressure decrease for vertical, horizontal, and inclined flow directions of oil and water flows. Test section lines of 4.19-in. (106.426 mm) inner diameter (ID) and 5-m horizontal, 5-m inclined, and 5-m vertical test sections were serially connected. The experiments were conducted at 40°C using 2-cp viscosity oil and tap water, and oil density of 850 kg/m3, at the standard conditions. Fifty experiments were executed at 250 kPa at the multiphase flow test facility, with horizontal, upward (0.6° and 4°), downward (−0.6° and −4°) hilly terrain and vertical pipes. The oil and water superficial velocities were changed between 0.03 and 2 m/s. This evidence was obtained using video recordings; the flow patterns were observed, and the selection of each flow pattern was depicted for each condition. For horizontal and inclined flow, new flow patterns were documented (e.g., oil transfer in a line forms at the top of the pipeline, typically at high water rate, and water transfer at the lower part of the pipe at a high oil rate). The data were taken at each flow condition, resulting in new holdup and pressure drop. The results show that the flow rate and the pipe inclination angle have major impacts on the holdup and pressure drop performances. In the vertical flow, a clear peak was demonstrated by experiments after the superficial oil velocity reached a certain value. This peak is known as phase inversion point, where after this peak, the pressure starts declining as the superficial oil velocity increases. Also, slippage has been observed after varying inlet oil flow rates between the two phases. The experiments showed that with minor alteration in the inclination angle, the slippage was significantly changed. This study presented new experimental results (measured mainly at horizontal, inclined, and vertical flow conditions) of HW, flow pattern, and pressure drop. These findings are key evidence of the evolving oil-water and flowline estimate models.
{"title":"Experimental Investigation of Oil-Water Two-Phase Flow in Horizontal, Inclined, and Vertical Large-Diameter Pipes: Determination of Flow Patterns, Holdup, and Pressure Drop","authors":"T. Ganat, M. Hrairi, R. Gholami, Taha Abouargub, E. Motaei","doi":"10.2118/205516-pa","DOIUrl":"https://doi.org/10.2118/205516-pa","url":null,"abstract":"Liquid-liquid phase flow in pipes merits further investigation as a challenging issue that has very rich physics and is faced in everyday applications. It is the main problem challenging the fluid flow mechanism in the oil and gas industry. The pressure gradient of liquid flow and flow pattern are still the topics of numerous research projects. In this paper, the emphasis is on further investigation to research the flow pattern, water holdup (HW), and pressure decrease for vertical, horizontal, and inclined flow directions of oil and water flows. Test section lines of 4.19-in. (106.426 mm) inner diameter (ID) and 5-m horizontal, 5-m inclined, and 5-m vertical test sections were serially connected. The experiments were conducted at 40°C using 2-cp viscosity oil and tap water, and oil density of 850 kg/m3, at the standard conditions. Fifty experiments were executed at 250 kPa at the multiphase flow test facility, with horizontal, upward (0.6° and 4°), downward (−0.6° and −4°) hilly terrain and vertical pipes. The oil and water superficial velocities were changed between 0.03 and 2 m/s. This evidence was obtained using video recordings; the flow patterns were observed, and the selection of each flow pattern was depicted for each condition. For horizontal and inclined flow, new flow patterns were documented (e.g., oil transfer in a line forms at the top of the pipeline, typically at high water rate, and water transfer at the lower part of the pipe at a high oil rate). The data were taken at each flow condition, resulting in new holdup and pressure drop. The results show that the flow rate and the pipe inclination angle have major impacts on the holdup and pressure drop performances. In the vertical flow, a clear peak was demonstrated by experiments after the superficial oil velocity reached a certain value. This peak is known as phase inversion point, where after this peak, the pressure starts declining as the superficial oil velocity increases. Also, slippage has been observed after varying inlet oil flow rates between the two phases. The experiments showed that with minor alteration in the inclination angle, the slippage was significantly changed. This study presented new experimental results (measured mainly at horizontal, inclined, and vertical flow conditions) of HW, flow pattern, and pressure drop. These findings are key evidence of the evolving oil-water and flowline estimate models.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42920592","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}
A. Janczak, G. Oftedal, E. Nikjoo, M. Hoy, C. Puls, T. Florian, M. Kornberger, P. Knauhs, B. Davidescu, O. Huseby, T. Clemens
Horizontal wells are frequently used to increase injectivity and for cost-efficient production of mobilized oil in polymer-augmented waterfloods. Usually, only fluid and polymer production data at the wellhead of the production well are available. We used inflow tracer technology to determine changes in hydrocarbon influx owing to polymer injection and to determine the connection from various zones of the horizontal injector to the horizontal producer. Inflow tracer technology was introduced in horizontal polymer injection and production wells. In the production wells, tracers are released when they are contacted by water and oil. Oil and water tracer systems were used in the horizontal production wells. The changes in the observed tracer concentration were used to quantify changes in influx from various sections of the horizontal producers owing to polymer injection. The inflow tracer technology applied in the horizontal injection wells demonstrates connectivity between different sections of the injection wells and two surrounding vertical and horizontal production wells and opens the usage of this technology for interwell water tracer applications. Inflow tracer technology enables one to elucidate the inflow from various sections of the horizontal wells and the changes thereof, even quantifying changes in influx of various fluids (oil and water). The information shows which sections are contributing and the substantial changes in the influx of oil from the various zones due to polymer solution injection. The overall incremental oil could be allocated to the various horizontal well sections based on the tracer results. Even zones that almost exclusively produced water before polymer injection showed a significant increase in oil influx. The inflow tracer technology installed in the injection well allowed us to analyze the connectivity of the injector to producer not only globally but spatially along the horizontal well. These data are used for reservoir characterization, to condition numerical models, and for reservoir management. Conventional interwell tracer technology allows one to determine the connectivity and connected volumes of horizontal well polymer field developments. However, it reveals neither information about influx of the sections nor the connectivity of various sections of the horizontal wells. Inflow tracer technology closes this gap; it allows one to quantify changes in influx of the fluids. Furthermore, the newly developed installed injection well tracer technology gives spatial information about the connectivity of the horizontal well sections.
{"title":"Monitoring Polymer Flooding Performance Using Inflow Tracer Technology in Horizontal Injection and Production Wells","authors":"A. Janczak, G. Oftedal, E. Nikjoo, M. Hoy, C. Puls, T. Florian, M. Kornberger, P. Knauhs, B. Davidescu, O. Huseby, T. Clemens","doi":"10.2118/205133-pa","DOIUrl":"https://doi.org/10.2118/205133-pa","url":null,"abstract":"\u0000 Horizontal wells are frequently used to increase injectivity and for cost-efficient production of mobilized oil in polymer-augmented waterfloods. Usually, only fluid and polymer production data at the wellhead of the production well are available. We used inflow tracer technology to determine changes in hydrocarbon influx owing to polymer injection and to determine the connection from various zones of the horizontal injector to the horizontal producer.\u0000 Inflow tracer technology was introduced in horizontal polymer injection and production wells. In the production wells, tracers are released when they are contacted by water and oil. Oil and water tracer systems were used in the horizontal production wells. The changes in the observed tracer concentration were used to quantify changes in influx from various sections of the horizontal producers owing to polymer injection. The inflow tracer technology applied in the horizontal injection wells demonstrates connectivity between different sections of the injection wells and two surrounding vertical and horizontal production wells and opens the usage of this technology for interwell water tracer applications.\u0000 Inflow tracer technology enables one to elucidate the inflow from various sections of the horizontal wells and the changes thereof, even quantifying changes in influx of various fluids (oil and water). The information shows which sections are contributing and the substantial changes in the influx of oil from the various zones due to polymer solution injection. The overall incremental oil could be allocated to the various horizontal well sections based on the tracer results. Even zones that almost exclusively produced water before polymer injection showed a significant increase in oil influx. The inflow tracer technology installed in the injection well allowed us to analyze the connectivity of the injector to producer not only globally but spatially along the horizontal well. These data are used for reservoir characterization, to condition numerical models, and for reservoir management.\u0000 Conventional interwell tracer technology allows one to determine the connectivity and connected volumes of horizontal well polymer field developments. However, it reveals neither information about influx of the sections nor the connectivity of various sections of the horizontal wells. Inflow tracer technology closes this gap; it allows one to quantify changes in influx of the fluids. Furthermore, the newly developed installed injection well tracer technology gives spatial information about the connectivity of the horizontal well sections.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49193433","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}
Hydrates are ice-like solids composed of a water-based lattice “encaging” gas molecules. They form under conditions of high pressure and low temperature. In the oil and gas industry, where these conditions are easily met, hydrate formation may cause pipe blockages and severe financial implications, making its prevention (and remediation) one of the main flow-assurance concerns. Desired hydrate inhibition may come from electrolytes naturally dissolved in the water that is produced in conjunction with the hydrocarbon stream, or alcohols can be deliberately injected for such a purpose. When trying to predict hydrate conditions in real-world production systems, computer simulation should ideally integrate hydrate and multiphase-flow calculations. Failing to do so [by performing a decoupled analysis with a flow simulator and a separate pressure/volume/temperature (PVT) package for example] may generate misleading results under certain flow conditions. This paper presents an integrated wellbore simulator to deal with this issue. A hydrate model is added to verify hydrate formation for specific pressure, temperature, and composition of each gridblock. Integration with a geochemical package allows consideration of electrolyte inhibition coming from the associated brine. After successfully comparing results with the available simulators and the experimental data, it is demonstrated that when flowing gas/water ratios (GWRs) exceed 105 scf/STB, water condensation throughout the flow may dilute the beneficial effect arising from the brine composition, thus reducing electrolyte inhibition. Conversely, mineral precipitation along the flow path has shown a nearly negligible impact on this effect.
{"title":"A Coupled Hydrate and Compositional Wellbore Simulator: Understanding Hydrate Inhibition from Associated Brines in Oil and Gas Production","authors":"F. Coelho, K. Sepehrnoori, O. Ezekoye","doi":"10.2118/206716-pa","DOIUrl":"https://doi.org/10.2118/206716-pa","url":null,"abstract":"\u0000 Hydrates are ice-like solids composed of a water-based lattice “encaging” gas molecules. They form under conditions of high pressure and low temperature. In the oil and gas industry, where these conditions are easily met, hydrate formation may cause pipe blockages and severe financial implications, making its prevention (and remediation) one of the main flow-assurance concerns. Desired hydrate inhibition may come from electrolytes naturally dissolved in the water that is produced in conjunction with the hydrocarbon stream, or alcohols can be deliberately injected for such a purpose. When trying to predict hydrate conditions in real-world production systems, computer simulation should ideally integrate hydrate and multiphase-flow calculations. Failing to do so [by performing a decoupled analysis with a flow simulator and a separate pressure/volume/temperature (PVT) package for example] may generate misleading results under certain flow conditions. This paper presents an integrated wellbore simulator to deal with this issue. A hydrate model is added to verify hydrate formation for specific pressure, temperature, and composition of each gridblock. Integration with a geochemical package allows consideration of electrolyte inhibition coming from the associated brine. After successfully comparing results with the available simulators and the experimental data, it is demonstrated that when flowing gas/water ratios (GWRs) exceed 105 scf/STB, water condensation throughout the flow may dilute the beneficial effect arising from the brine composition, thus reducing electrolyte inhibition. Conversely, mineral precipitation along the flow path has shown a nearly negligible impact on this effect.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45775567","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}
Hamdi Mnasri, M. Franchek, Taoufik Wassar, Yingjie Tang, A. Meziou
Presented is a model-based methodology identifying subsea field architectures that satisfy prespecified multiphysics constraints. The proposed methodology prioritizes the identified subsea system using a multiobjective optimization approach considering two objective functions, which are minimizing pressure drop reflecting the maximization of production flow rates and minimizing capital expenditures. The architecture solutions produce manifolds positioning and optimal pipeline routing/sizing. A convex combination approach creates the multiobjective optimization criterion enabling weighting among constraints such as hydraulic, topological, structural, and flow assurance, as well as technical issues and financial limitations. The optimization problem is computationally solved using a hybrid method with a global multistart algorithm that combines a scatter search process with a gradient-based local nonlinear problem solver. A case study is provided to test the proposed methodology including the effect of varying the weights among the constraints. This deep-dive analysis demonstrates the potential offered by the proposed methodology, illustrated by the ability to perform several investigations such as wells-grouping analysis and insulation effect on the overall optimization procedure, as well as to provide a tracking tool for flow-assurance factors, namely erosion and corrosion rates along the subsea layout. Hence, we present a demonstration of the capabilities of the proposed model-based subsea field layout optimization procedure.
{"title":"Model-Based Simulation Approach for Pre-Front End Engineering Design Studies for Subsea Field Architecture Development","authors":"Hamdi Mnasri, M. Franchek, Taoufik Wassar, Yingjie Tang, A. Meziou","doi":"10.2118/205508-PA","DOIUrl":"https://doi.org/10.2118/205508-PA","url":null,"abstract":"\u0000 Presented is a model-based methodology identifying subsea field architectures that satisfy prespecified multiphysics constraints. The proposed methodology prioritizes the identified subsea system using a multiobjective optimization approach considering two objective functions, which are minimizing pressure drop reflecting the maximization of production flow rates and minimizing capital expenditures. The architecture solutions produce manifolds positioning and optimal pipeline routing/sizing. A convex combination approach creates the multiobjective optimization criterion enabling weighting among constraints such as hydraulic, topological, structural, and flow assurance, as well as technical issues and financial limitations. The optimization problem is computationally solved using a hybrid method with a global multistart algorithm that combines a scatter search process with a gradient-based local nonlinear problem solver. A case study is provided to test the proposed methodology including the effect of varying the weights among the constraints. This deep-dive analysis demonstrates the potential offered by the proposed methodology, illustrated by the ability to perform several investigations such as wells-grouping analysis and insulation effect on the overall optimization procedure, as well as to provide a tracking tool for flow-assurance factors, namely erosion and corrosion rates along the subsea layout. Hence, we present a demonstration of the capabilities of the proposed model-based subsea field layout optimization procedure.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":"1-21"},"PeriodicalIF":1.2,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44047249","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}
Cost and schedule overruns are endemic problems for offshore oil projects. This can be partly attributed to weather delays, resource limitations, and scheduling risks. The problem is further compounded because of the large number of interdependent activities, such as drilling and platform installation, typically involved in the buildup period of oilfield development. As a result, there is a pressing need to find robust project planning and scheduling models that consider these interacting components and associated risks in offshore oil projects. This study considers three techniques to optimize offshore oil project schedules while accounting for the impact of numerous field activities and potential delay factors; these are mixed-integer linear programming (MILP), single-objective genetic algorithms (SOGAs), and nondominated sorting genetic algorithms (NSGA-II). The study compares the performance of each using a model that integrates field planning with scheduling while accounting for weather delays, resource limitations, and simultaneous operations (SIMOPS; i.e., the ability to conduct more than one activity at once). The first two techniques (MILP and SOGA) optimize the oilfield schedule based on a single objective, which is to maximize net present value (NPV) or minimize project time. However, the maximum NPV schedule may result in a longer project time, whereas the shortest project time may result in a lower NPV. Therefore, the third method using NSGA-II finds Pareto-optimal schedules that balance these competing objectives. Four case studies are provided to compare the MILP and SOGA approaches with the suggested multiobjective NSGA-II.
{"title":"Schedule Optimization To Accelerate Offshore Oil Projects While Maximizing Net Present Value in the Presence of Simultaneous Operations, Weather Delays, and Resource Limitations","authors":"Mohammed K. Almedallah, Stuart R. Clark, S. Walsh","doi":"10.2118/205521-PA","DOIUrl":"https://doi.org/10.2118/205521-PA","url":null,"abstract":"\u0000 Cost and schedule overruns are endemic problems for offshore oil projects. This can be partly attributed to weather delays, resource limitations, and scheduling risks. The problem is further compounded because of the large number of interdependent activities, such as drilling and platform installation, typically involved in the buildup period of oilfield development. As a result, there is a pressing need to find robust project planning and scheduling models that consider these interacting components and associated risks in offshore oil projects.\u0000 This study considers three techniques to optimize offshore oil project schedules while accounting for the impact of numerous field activities and potential delay factors; these are mixed-integer linear programming (MILP), single-objective genetic algorithms (SOGAs), and nondominated sorting genetic algorithms (NSGA-II). The study compares the performance of each using a model that integrates field planning with scheduling while accounting for weather delays, resource limitations, and simultaneous operations (SIMOPS; i.e., the ability to conduct more than one activity at once). The first two techniques (MILP and SOGA) optimize the oilfield schedule based on a single objective, which is to maximize net present value (NPV) or minimize project time. However, the maximum NPV schedule may result in a longer project time, whereas the shortest project time may result in a lower NPV. Therefore, the third method using NSGA-II finds Pareto-optimal schedules that balance these competing objectives. Four case studies are provided to compare the MILP and SOGA approaches with the suggested multiobjective NSGA-II.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":"1-18"},"PeriodicalIF":1.2,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47690797","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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