In order to properly conduct material balance calculations, the wells must be producing from the same reservoir. Identification and grouping of wells in a common reservoir can be a challenging task. The Flowing Material Balance Model (FMB model) was developed. It utilizes a well’s flow rate and flowing pressure history to identify which wells belong in the same reservoir, and which do not. This FMB Model continuously converts the flowing pressures and rates of each well into the average reservoir pressure. If these average reservoir pressure trends overlap, it indicates that the wells are in the same reservoir. If any of the trends are different, then those wells belong to different reservoirs. The average reservoir pressure is determined in two ways. The first is from the productivity index and the flowing rates and pressures of that well. The second is from the material balance equation for the total production of the group of wells. These two average reservoir pressure trends will track over time if the well grouping is properly defined (i.e. all the wells in that grouping belong to the same reservoir), and if the correct hydrocarbon-in-place is used. The FMB Model can additionally be used to history-match the flowing pressure of each well (using the flow rate as a control) or to match the flow rate of each well (using the flowing pressure as a control). These visual history matches increase our confidence in the interpretation of the flowing material balance, and can be used to investigate the sensitivity of magnitude of the hydrocarbons-in-place One field study consisting of three adjacent gas wells, coming on production at different times, and some of the wells not having a reliable initial pressure, illustrates clearly which wells are in the same reservoir and which ones are not, and yields the correct values of original-gas-in-place.
{"title":"Using the FMB Model to Determine Which Wells Out of a Group of Wells Belong to the Same Common Pool","authors":"S. Tabatabaie, H. Behmanesh, L. Mattar","doi":"10.2118/208944-ms","DOIUrl":"https://doi.org/10.2118/208944-ms","url":null,"abstract":"\u0000 In order to properly conduct material balance calculations, the wells must be producing from the same reservoir. Identification and grouping of wells in a common reservoir can be a challenging task.\u0000 The Flowing Material Balance Model (FMB model) was developed. It utilizes a well’s flow rate and flowing pressure history to identify which wells belong in the same reservoir, and which do not. This FMB Model continuously converts the flowing pressures and rates of each well into the average reservoir pressure. If these average reservoir pressure trends overlap, it indicates that the wells are in the same reservoir. If any of the trends are different, then those wells belong to different reservoirs.\u0000 The average reservoir pressure is determined in two ways. The first is from the productivity index and the flowing rates and pressures of that well. The second is from the material balance equation for the total production of the group of wells. These two average reservoir pressure trends will track over time if the well grouping is properly defined (i.e. all the wells in that grouping belong to the same reservoir), and if the correct hydrocarbon-in-place is used.\u0000 The FMB Model can additionally be used to history-match the flowing pressure of each well (using the flow rate as a control) or to match the flow rate of each well (using the flowing pressure as a control). These visual history matches increase our confidence in the interpretation of the flowing material balance, and can be used to investigate the sensitivity of magnitude of the hydrocarbons-in-place\u0000 One field study consisting of three adjacent gas wells, coming on production at different times, and some of the wells not having a reliable initial pressure, illustrates clearly which wells are in the same reservoir and which ones are not, and yields the correct values of original-gas-in-place.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88372621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In recent years, interest in water-based EOR methods and the combination of modified seawater with chemicals has grown due to their economic improvement of oil production. The hybrid application of low salinity water with surfactants (LSS) flooding has a promising potential to significantly increase the oil recovery. LSS flooding, a novel hybrid EOR approach, has recently proven its capability of altering rock surface wettability and reducing oil-water IFT. In this study, we present a comprehensive assessment of the fundamentals and recent developments of LSS flooding, as well as lessons learned from previous studies and the key uncertainties associated with successful implementation. The study begins with an overview of surfactant flooding, low salinity water (LSW) flooding and the hybrid application of LSW flooding processes. The LSS flooding process in different reservoir types and the recovery mechanisms associated is then discussed. The recent laboratory studies for LSS flooding and the surfactant losses associated in porous media are also reviewed. Recent studies of LSS flooding have concluded the advantages of higher oil recovery, higher surfactant stability, lower surfactant retention, and lower chemical consumption compared to conventional surfactant flooding. Most of the LSS flooding application has been performed on sandstones with remarkable outcomes, meanwhile, it’s application in carbonates has garnered attention in recent years and some promising findings were reported. The efforts of this work can provide further understanding of the LSS flooding process and its underlying mechanisms, especially in carbonates which are not fully covered in the literature. Finally, this paper gives more insight into the potential success of LSS flooding over surfactant and LSW flooding processes.
{"title":"Critical Assessment of the Hybrid Impact of Surfactants on Modified Salinity Water Flooding","authors":"A. Belhaj, N. Singh, H. Sarma","doi":"10.2118/208974-ms","DOIUrl":"https://doi.org/10.2118/208974-ms","url":null,"abstract":"\u0000 In recent years, interest in water-based EOR methods and the combination of modified seawater with chemicals has grown due to their economic improvement of oil production. The hybrid application of low salinity water with surfactants (LSS) flooding has a promising potential to significantly increase the oil recovery. LSS flooding, a novel hybrid EOR approach, has recently proven its capability of altering rock surface wettability and reducing oil-water IFT. In this study, we present a comprehensive assessment of the fundamentals and recent developments of LSS flooding, as well as lessons learned from previous studies and the key uncertainties associated with successful implementation. The study begins with an overview of surfactant flooding, low salinity water (LSW) flooding and the hybrid application of LSW flooding processes. The LSS flooding process in different reservoir types and the recovery mechanisms associated is then discussed. The recent laboratory studies for LSS flooding and the surfactant losses associated in porous media are also reviewed. Recent studies of LSS flooding have concluded the advantages of higher oil recovery, higher surfactant stability, lower surfactant retention, and lower chemical consumption compared to conventional surfactant flooding. Most of the LSS flooding application has been performed on sandstones with remarkable outcomes, meanwhile, it’s application in carbonates has garnered attention in recent years and some promising findings were reported. The efforts of this work can provide further understanding of the LSS flooding process and its underlying mechanisms, especially in carbonates which are not fully covered in the literature. Finally, this paper gives more insight into the potential success of LSS flooding over surfactant and LSW flooding processes.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82367894","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Xianglin Xu, Alexander Albuja, A. Izurieta, Xuepeng Wan, Hua Yang, Zhengwen Wang
To analyze some factors that affect electrical submersible pump (ESP) performance and its reliability, focused on sand control practices (downhole devices as well as chemical sand consolidation), fluid characterization, and bending stress effects. To describe some study cases where these practices were applied over the last ten years leading to an increase in ESP reliability. To show ESP performance for 74 installations executed during the latest development stage in the Tarapoa block. ESP performance in Tarapoa is affected by downhole devices sand production efficiency such as screens, automatic solids fallback preventer valves, and chemical sand consolidation treatments, the study starts with a summary of these experiences and related issues. Viscosity influence on ESP performance is studied since design stage sensitivity to water cut, emulsion, API gravity, and sand content is included. During the production stage, the need for single, double, or multiport capillary systems is described as well as the chemicals used. The finite element method is used to evaluate the stress effect during ESP installation and optimal setting depth for different well trajectories. The best method for sand control in directional wells is chemical sand consolidation, this technique does not require additional downhole equipment and the effect on the productivity index is negligible. Standalone screens are recommended for horizontal wells but their effectiveness in sand production is limited. Automatic solids fallback valve provides some protection to ESP by preventing sand deposition when well is shut-in, up to 2,320 days running with this equipment. The production status of ESP under different viscosity conditions is simulated improving ESP run life. In addition, chemical injection effectively improves the physical properties of the fluid, which makes ESP relatively stable. Through the application of finite element software, a reliable stress distribution through the equipment was obtained. This analysis is used during installation operation and to define recommended setting depth. Average ESP run life extended over 1,900 days with a Mean Time Between Failure (MTBF) over 4,000 days. This study summarizes the practices used to improve ESP performance over the last 10 years. ESP performance is affected by various factors that are described in this study from downhole sand control devices, chemical treatments, accessories installed along with ESP, and chemicals used during the production stage.
{"title":"Sand Management Practices for Extended ESP Run Life, a Study Case from a Mature Field in Ecuador","authors":"Xianglin Xu, Alexander Albuja, A. Izurieta, Xuepeng Wan, Hua Yang, Zhengwen Wang","doi":"10.2118/208911-ms","DOIUrl":"https://doi.org/10.2118/208911-ms","url":null,"abstract":"\u0000 To analyze some factors that affect electrical submersible pump (ESP) performance and its reliability, focused on sand control practices (downhole devices as well as chemical sand consolidation), fluid characterization, and bending stress effects. To describe some study cases where these practices were applied over the last ten years leading to an increase in ESP reliability. To show ESP performance for 74 installations executed during the latest development stage in the Tarapoa block.\u0000 ESP performance in Tarapoa is affected by downhole devices sand production efficiency such as screens, automatic solids fallback preventer valves, and chemical sand consolidation treatments, the study starts with a summary of these experiences and related issues. Viscosity influence on ESP performance is studied since design stage sensitivity to water cut, emulsion, API gravity, and sand content is included. During the production stage, the need for single, double, or multiport capillary systems is described as well as the chemicals used. The finite element method is used to evaluate the stress effect during ESP installation and optimal setting depth for different well trajectories.\u0000 The best method for sand control in directional wells is chemical sand consolidation, this technique does not require additional downhole equipment and the effect on the productivity index is negligible. Standalone screens are recommended for horizontal wells but their effectiveness in sand production is limited. Automatic solids fallback valve provides some protection to ESP by preventing sand deposition when well is shut-in, up to 2,320 days running with this equipment. The production status of ESP under different viscosity conditions is simulated improving ESP run life. In addition, chemical injection effectively improves the physical properties of the fluid, which makes ESP relatively stable. Through the application of finite element software, a reliable stress distribution through the equipment was obtained. This analysis is used during installation operation and to define recommended setting depth. Average ESP run life extended over 1,900 days with a Mean Time Between Failure (MTBF) over 4,000 days.\u0000 This study summarizes the practices used to improve ESP performance over the last 10 years. ESP performance is affected by various factors that are described in this study from downhole sand control devices, chemical treatments, accessories installed along with ESP, and chemicals used during the production stage.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79841856","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper demonstrates how a novel electromagnetic induction heating technology can be used to recover oil from the Athabasca oil sands of Alberta with minimal environmental impact. The paper compares the new technology to other electromagmetic heating technologies for oil sands, exhibits how electromagnetic induction heating is coupled to the reservoir, and addresses requirements of the new technology for economic production. The patent pending inductor design generates thermal energy in a reservoir model representing a 33 meter pay zone with properties for the lower McMurray formation in an area north of Fort McMurray within the Athabasca oil sands deposit. Electromagnetic energy is coupled to the reservoir in an iterative process that enables operators to monitor and control reservoir temperature, pressure, fluid production, and energy to oil ratio, to enhance recovery of heavy oil and bitumen. This is performed by interfacing commercial electromagnetic and reservoir simulators using an in-house coupling script. The results demonstrate an ultimate oil recovery factor of +70% with an energy to oil ratio lower than 200 kilowatt hour per barrel. This is less energy per barrel than the average energy required by steam assisted gravity drainage. Though not compulsory for the process, it is observed that oil recovery is improved with water injection. This is mainly because the amount of electromagnetic energy coupled to the reservoir correlates with water saturation in the near wellbore region. Water injection helps maintain water saturation levels and improves heat convection further into the reservoir. Nonetheless, there is no need for external water supply, because the volume of injected water required to improve oil recovery is comparable to the overall volume of water produced from the reservoir. Unlike other recovery methods, this technology is expected to have low energy intensity, zero emissions, and minimized land footprint leading to responsible bitumen recovery. This paper sheds light on the capability of an innovative clean energy technology to enhance bitumen recovery from the Athabasca oil sands in Alberta. The novel technology takes advantage of clean energy to recover oil at a lower energy to oil ratio than the average ratio achieved with steam injection methods.
{"title":"Electromagnetic Induction Heating Technology for Enhanced Heavy Oil and Bitumen Recovery","authors":"A. Sherwali, M. Noroozi, W. Dunford","doi":"10.2118/208907-ms","DOIUrl":"https://doi.org/10.2118/208907-ms","url":null,"abstract":"\u0000 This paper demonstrates how a novel electromagnetic induction heating technology can be used to recover oil from the Athabasca oil sands of Alberta with minimal environmental impact. The paper compares the new technology to other electromagmetic heating technologies for oil sands, exhibits how electromagnetic induction heating is coupled to the reservoir, and addresses requirements of the new technology for economic production.\u0000 The patent pending inductor design generates thermal energy in a reservoir model representing a 33 meter pay zone with properties for the lower McMurray formation in an area north of Fort McMurray within the Athabasca oil sands deposit. Electromagnetic energy is coupled to the reservoir in an iterative process that enables operators to monitor and control reservoir temperature, pressure, fluid production, and energy to oil ratio, to enhance recovery of heavy oil and bitumen. This is performed by interfacing commercial electromagnetic and reservoir simulators using an in-house coupling script.\u0000 The results demonstrate an ultimate oil recovery factor of +70% with an energy to oil ratio lower than 200 kilowatt hour per barrel. This is less energy per barrel than the average energy required by steam assisted gravity drainage. Though not compulsory for the process, it is observed that oil recovery is improved with water injection. This is mainly because the amount of electromagnetic energy coupled to the reservoir correlates with water saturation in the near wellbore region. Water injection helps maintain water saturation levels and improves heat convection further into the reservoir. Nonetheless, there is no need for external water supply, because the volume of injected water required to improve oil recovery is comparable to the overall volume of water produced from the reservoir.\u0000 Unlike other recovery methods, this technology is expected to have low energy intensity, zero emissions, and minimized land footprint leading to responsible bitumen recovery. This paper sheds light on the capability of an innovative clean energy technology to enhance bitumen recovery from the Athabasca oil sands in Alberta. The novel technology takes advantage of clean energy to recover oil at a lower energy to oil ratio than the average ratio achieved with steam injection methods.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"64 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84665611","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Oil and gas wells that have reached their economic end of life or have never been put into production for any reason may have potential for an alternate form of energy. Geothermal energy can be extracted from wells and is dependent upon numerous factors, but primarily by the thermal gradient of the region and the well depth. These two primary factors cannot be altered, however the design of the completion and production systems for extracting geothermal energy can significantly impact the amount of energy that can be extracted. This paper presents results from evaluating the rate of thermal energy that can be extracted under various completion scenarios using a transient flow simulator. This evaluation was conducted on closed loop systems whereby the fluids are contained within the well bore and surface facilities and do not involve any formation fluids. The results from the transient flow simulator show that the direction of flow circulation and insulation of the tubing string are crucial in evaluating assorted options to diminish thermal losses. There is an economic decision required for the decision on insulation type Results were also obtained for using the system to store energy in the upper regions of the well during time periods when there is no heat required from the system. This improves thermal recovery efficiencies when heat demand returns. Based on analyses of the simulations the two-stage storage/extraction processes significantly improved the technical, economic and environmental merits of the previously developed coaxial technology for heat generation. The use of a multiphase flow simulator for this study provides a roadmap for understanding the thermal energy potential, as well as the most important variables when considering extraction of geothermal energy from existing oil and gas wells.
{"title":"Optimizing Geothermal Heat Extraction from End of Life Oil & Gas Wells Using a Transient Multiphase Flow Simulator","authors":"D. Sask, P. Graham, C. Nascimento","doi":"10.2118/208928-ms","DOIUrl":"https://doi.org/10.2118/208928-ms","url":null,"abstract":"Oil and gas wells that have reached their economic end of life or have never been put into production for any reason may have potential for an alternate form of energy. Geothermal energy can be extracted from wells and is dependent upon numerous factors, but primarily by the thermal gradient of the region and the well depth. These two primary factors cannot be altered, however the design of the completion and production systems for extracting geothermal energy can significantly impact the amount of energy that can be extracted.\u0000 This paper presents results from evaluating the rate of thermal energy that can be extracted under various completion scenarios using a transient flow simulator. This evaluation was conducted on closed loop systems whereby the fluids are contained within the well bore and surface facilities and do not involve any formation fluids.\u0000 The results from the transient flow simulator show that the direction of flow circulation and insulation of the tubing string are crucial in evaluating assorted options to diminish thermal losses. There is an economic decision required for the decision on insulation type\u0000 Results were also obtained for using the system to store energy in the upper regions of the well during time periods when there is no heat required from the system. This improves thermal recovery efficiencies when heat demand returns. Based on analyses of the simulations the two-stage storage/extraction processes significantly improved the technical, economic and environmental merits of the previously developed coaxial technology for heat generation.\u0000 The use of a multiphase flow simulator for this study provides a roadmap for understanding the thermal energy potential, as well as the most important variables when considering extraction of geothermal energy from existing oil and gas wells.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83682640","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The non-thermal solvent-based processes for bitumen extraction consume less energy and water, and thus, have less impacts on the environment compared with the steam-based thermal processes. The objective of this paper is to investigate the mechanisms responsible for propane transport into and bitumen production from oil-sand core samples during the cyclic solvent injection (CSI). We use a state-of-the-art high-pressure and high-temperature (HPHT) visualization cell to investigate non-equilibrium propane-bitumen interactions during CSI. We inject propane into the cell containing a bitumen-saturated core plug representing in-situ reservoir conditions. Three sets of tests with different propane vapor (C3(v)) to liquid (C3(l)) ratio are conducted (set 1 with C3(l), set 2 with C3(l)-C3(v) mixture, and set 3 with C3(v)). After the CSI tests, the final bitumen recovery factor is calculated by the weight-balance method and the precipitated asphaltene content caused by propane-bitumen interactions is also measured using a distillation apparatus. When the core is fully immersed in C3(l), the cell pressure rapidly declines during the early soaking process, and then, it declines gradually. However, no obvious pressure decline can be observed when C3(v) is present in the system. This can be explained by the higher compressibility of C3(v) compared to C3(l), leading to a less significant pressure decline during the soaking period. A light hydrocarbon phase is produced from the core at the end of the depletion process, indicating the extraction of light components of oil by propane even at low-temperature conditions. The bitumen recovery factor is the lowest (11.93%) in set 1 when the core is soaked in C3(l), while that is the highest (14.73%) in set 3 when the core is soaked in C3(v). Also, the bitumen production stops quickly at the early soaking period in set 1. This is because asphaltene precipitation is more significant when the C3(l) is present in the system. The propane density in liquid state is higher than that in vapor state, leading to more bitumen-propane interactions and more asphaltene precipitation. The precipitated asphaltene blocks the pore network and inhibits bitumen production. Our results show that increasing C3(v) to C3(v) ratio decreases the amount of asphaltene precipitation, and in turn, increases bitumen recovery factor.
{"title":"The Effects of Asphaltene Precipitation on Bitumen Recovery during Non-Thermal Cyclic Solvent Injection in Cold Lake Oil Sands- An Experimental Study","authors":"Lijuan Yuan, M. Yousefi, H. Dehghanpour","doi":"10.2118/208919-ms","DOIUrl":"https://doi.org/10.2118/208919-ms","url":null,"abstract":"\u0000 The non-thermal solvent-based processes for bitumen extraction consume less energy and water, and thus, have less impacts on the environment compared with the steam-based thermal processes. The objective of this paper is to investigate the mechanisms responsible for propane transport into and bitumen production from oil-sand core samples during the cyclic solvent injection (CSI). We use a state-of-the-art high-pressure and high-temperature (HPHT) visualization cell to investigate non-equilibrium propane-bitumen interactions during CSI. We inject propane into the cell containing a bitumen-saturated core plug representing in-situ reservoir conditions. Three sets of tests with different propane vapor (C3(v)) to liquid (C3(l)) ratio are conducted (set 1 with C3(l), set 2 with C3(l)-C3(v) mixture, and set 3 with C3(v)). After the CSI tests, the final bitumen recovery factor is calculated by the weight-balance method and the precipitated asphaltene content caused by propane-bitumen interactions is also measured using a distillation apparatus.\u0000 When the core is fully immersed in C3(l), the cell pressure rapidly declines during the early soaking process, and then, it declines gradually. However, no obvious pressure decline can be observed when C3(v) is present in the system. This can be explained by the higher compressibility of C3(v) compared to C3(l), leading to a less significant pressure decline during the soaking period. A light hydrocarbon phase is produced from the core at the end of the depletion process, indicating the extraction of light components of oil by propane even at low-temperature conditions. The bitumen recovery factor is the lowest (11.93%) in set 1 when the core is soaked in C3(l), while that is the highest (14.73%) in set 3 when the core is soaked in C3(v). Also, the bitumen production stops quickly at the early soaking period in set 1. This is because asphaltene precipitation is more significant when the C3(l) is present in the system. The propane density in liquid state is higher than that in vapor state, leading to more bitumen-propane interactions and more asphaltene precipitation. The precipitated asphaltene blocks the pore network and inhibits bitumen production. Our results show that increasing C3(v) to C3(v) ratio decreases the amount of asphaltene precipitation, and in turn, increases bitumen recovery factor.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74597277","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The standard test procedure for paraffin inhibitor evaluations in oil and gas production over the past 20 years has been cold finger analysis. With the emergence of unconventional Canadian oil and gas production from tight reservoirs such as the Montney and Duvernay formations, mounting paraffin treatment issues have been observed. The limitations of cold finger analysis have become increasingly evident when relating product evaluation data to field performance data. Baker Hughes has developed a method to evaluate paraffin inhibitors using differential scanning calorimetry (DSC) that exhibits key improvements over cold finger analysis. The results of an investigation between product evaluation testing through DSC and field performance data is presented. DSC analysis is commonly used in the oil and gas industry for cloud point or wax appearance temperature (WAT) determination of crude oil by detecting the point at which paraffin crystals form. It has commonly been presumed that detection of cloud point shifting can be accomplished with paraffin inhibitor chemistries; however, contradictory evidence obtained through thorough investigation within the industry refutes this claim. This is due to the fact that standard paraffin inhibitors work to disrupt paraffin crystal growth and agglomeration, instead of paraffin crystal suppression. Many programs identified through DSC testing methodology have been successfully implemented in a variety of field applications including both conventional and unconventional production. Moreover, field application monitoring data correlates to product selection and treatment rate data obtained through DSC analysis far better than results acquired through cold finger analysis. Additionally, analysis through DSC is far less susceptible to commonly experienced interferences observed in cold finger analysis such as high asphaltene content of specific crude oils, or paraffin content of condensate. Paraffin inhibitor evaluation through DSC allows for improved understanding of intended paraffin inhibitor programs for oil and gas producers, especially those experiencing difficult to treat paraffin issues in higher temperature tight reservoirs.
{"title":"Understanding Field Performance of Paraffin Inhibitors Using Differential Scanning Calorimetry","authors":"Matthew Shuya, Holley Baron, Cristino Tiberio","doi":"10.2118/208978-ms","DOIUrl":"https://doi.org/10.2118/208978-ms","url":null,"abstract":"\u0000 The standard test procedure for paraffin inhibitor evaluations in oil and gas production over the past 20 years has been cold finger analysis. With the emergence of unconventional Canadian oil and gas production from tight reservoirs such as the Montney and Duvernay formations, mounting paraffin treatment issues have been observed. The limitations of cold finger analysis have become increasingly evident when relating product evaluation data to field performance data. Baker Hughes has developed a method to evaluate paraffin inhibitors using differential scanning calorimetry (DSC) that exhibits key improvements over cold finger analysis. The results of an investigation between product evaluation testing through DSC and field performance data is presented.\u0000 DSC analysis is commonly used in the oil and gas industry for cloud point or wax appearance temperature (WAT) determination of crude oil by detecting the point at which paraffin crystals form. It has commonly been presumed that detection of cloud point shifting can be accomplished with paraffin inhibitor chemistries; however, contradictory evidence obtained through thorough investigation within the industry refutes this claim. This is due to the fact that standard paraffin inhibitors work to disrupt paraffin crystal growth and agglomeration, instead of paraffin crystal suppression.\u0000 Many programs identified through DSC testing methodology have been successfully implemented in a variety of field applications including both conventional and unconventional production. Moreover, field application monitoring data correlates to product selection and treatment rate data obtained through DSC analysis far better than results acquired through cold finger analysis. Additionally, analysis through DSC is far less susceptible to commonly experienced interferences observed in cold finger analysis such as high asphaltene content of specific crude oils, or paraffin content of condensate.\u0000 Paraffin inhibitor evaluation through DSC allows for improved understanding of intended paraffin inhibitor programs for oil and gas producers, especially those experiencing difficult to treat paraffin issues in higher temperature tight reservoirs.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"282 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74675746","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Farzan Sahari Moghaddam, M. Mahmoodi, M. Zare, F. Goodarzi, M. Abdi, L. James
Preventing hydrate formation is critical to safely and economically manage subsea tiebacks. Thermodynamic Hydrate Inhibitors (THI) and Low Dosage Hydrate Inhibitors (LDHI) help manage hydrate formation. Here, we use a novel isothermal approach using a PVT cell to experimentally find the hydrate equilibrium point of natural gas and brine. In addition, a constant temperature and pressure condition is used to compare hydrate formation with and without hydrate inhibitors. First, to better understand the novel isothermal technique, natural gas-brine equilibrium experiments were conducted. Secondly, a constant pressure and temperature approach is used to investigate Kinetic Hydrate Inhibitors (KHIs) and low dosage methanol performance on hydrate formation. The formation and dissociation points are detected through a sudden drop or peak in the pressure profile, respectively, and by visual observation. To evaluate inhibitor performance, the experiments were conducted at challenging temperatures between -0.5°C to 3°C, applicable to the environment offshore Newfoundland and Labrador. Two commercial KHIs and one THI were tested. Both KHIs showed good performance up to certain level of subcooling according to their concentration. However, KHI-B performed better at inhibiting hydrates compared to KHI-A despite its lower concentrations compared to KHI-A. The induction time for 1 wt% KHI-A under 10°C subcooling at a temperature of 0.75°C was 311 min. The induction time for 1 wt% KHI-B under 12°C subcooling at a temperature of 2.66°C was 184 min. Yet, in the case of KHI B, with half the concentration (0.5 wt%), no hydrate formed at temperature of 1.21°C and 10°C subcooling. Low dosage methanol (a common THI) was also assessed. Although the induction time under 10.36°C subcooling and constant temperature of −0.43°C was only 47 min, no hydrate formed within 22 hours at −0.12°C under 7.5°C subcooling. This work uses a novel experimental isothermal approach by PVT cell to investigate hydrate equilibrium and the effectiveness of different inhibitors. Hence, a better understanding of natural gas hydrate equilibrium in brine is developed. Based on significant costs associated with injecting high quantities of THI (e.g., methanol) to prevent hydrate formation, this work also compares the performance of KHIs and low dosage THI (methanol).
{"title":"Natural Gas Hydrate Equilibria in Brine Including the Effect of Inhibitors on Hydrate Formation","authors":"Farzan Sahari Moghaddam, M. Mahmoodi, M. Zare, F. Goodarzi, M. Abdi, L. James","doi":"10.2118/208890-ms","DOIUrl":"https://doi.org/10.2118/208890-ms","url":null,"abstract":"\u0000 Preventing hydrate formation is critical to safely and economically manage subsea tiebacks. Thermodynamic Hydrate Inhibitors (THI) and Low Dosage Hydrate Inhibitors (LDHI) help manage hydrate formation. Here, we use a novel isothermal approach using a PVT cell to experimentally find the hydrate equilibrium point of natural gas and brine. In addition, a constant temperature and pressure condition is used to compare hydrate formation with and without hydrate inhibitors.\u0000 First, to better understand the novel isothermal technique, natural gas-brine equilibrium experiments were conducted. Secondly, a constant pressure and temperature approach is used to investigate Kinetic Hydrate Inhibitors (KHIs) and low dosage methanol performance on hydrate formation. The formation and dissociation points are detected through a sudden drop or peak in the pressure profile, respectively, and by visual observation. To evaluate inhibitor performance, the experiments were conducted at challenging temperatures between -0.5°C to 3°C, applicable to the environment offshore Newfoundland and Labrador.\u0000 Two commercial KHIs and one THI were tested. Both KHIs showed good performance up to certain level of subcooling according to their concentration. However, KHI-B performed better at inhibiting hydrates compared to KHI-A despite its lower concentrations compared to KHI-A. The induction time for 1 wt% KHI-A under 10°C subcooling at a temperature of 0.75°C was 311 min. The induction time for 1 wt% KHI-B under 12°C subcooling at a temperature of 2.66°C was 184 min. Yet, in the case of KHI B, with half the concentration (0.5 wt%), no hydrate formed at temperature of 1.21°C and 10°C subcooling. Low dosage methanol (a common THI) was also assessed. Although the induction time under 10.36°C subcooling and constant temperature of −0.43°C was only 47 min, no hydrate formed within 22 hours at −0.12°C under 7.5°C subcooling.\u0000 This work uses a novel experimental isothermal approach by PVT cell to investigate hydrate equilibrium and the effectiveness of different inhibitors. Hence, a better understanding of natural gas hydrate equilibrium in brine is developed. Based on significant costs associated with injecting high quantities of THI (e.g., methanol) to prevent hydrate formation, this work also compares the performance of KHIs and low dosage THI (methanol).","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"367 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76598448","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Comparative biocidal efficacy studies were conducted using field water samples. Biocide stock solutions were made up in field waters and tested before and after thermal aging to simulate downhole thermal conditions. Biocidal efficacy was measured by serial dilution vials and ATP. Tributyl tetradecyl phosphonium chloride (TTPC) provided rapid biocidal activity against sulfate-reducing and acid-producing bacteria in multiple field water samples. It was also thermally stable and retained all of its biocidal activity through 7 days of heat aging at downhole temperatures of 85-90°C. In contrast, non-oxidizing biocides based on 2-bromo-2-nitropropane-1,3-diol, 2,2-dibromo-3-nitrilopropionamide, and glutaraldehyde/quaternary ammonium chloride lost significant biocidal activity after exposure to these same downhole temperatures. TTPC also showed excellent compatibility with anionic friction reducers. Once the efficacy and compatibility of TTPC was confirmed in lab tests, it was used on several multi-well fracs. Results of the flowback testing gave zero viable sulfate-reducing and acid-producing bacteria and ATP values of <100 pg/ml in several wells, indicating that TTPC was highly effective at controlling microbial contamination in the harsh field environment.
{"title":"Bacteria Control in Unconventional High Temperature Dopwnhole Conditions During Completions","authors":"M. Graham, J. Kramer","doi":"10.2118/208930-ms","DOIUrl":"https://doi.org/10.2118/208930-ms","url":null,"abstract":"\u0000 Comparative biocidal efficacy studies were conducted using field water samples. Biocide stock solutions were made up in field waters and tested before and after thermal aging to simulate downhole thermal conditions. Biocidal efficacy was measured by serial dilution vials and ATP. Tributyl tetradecyl phosphonium chloride (TTPC) provided rapid biocidal activity against sulfate-reducing and acid-producing bacteria in multiple field water samples. It was also thermally stable and retained all of its biocidal activity through 7 days of heat aging at downhole temperatures of 85-90°C. In contrast, non-oxidizing biocides based on 2-bromo-2-nitropropane-1,3-diol, 2,2-dibromo-3-nitrilopropionamide, and glutaraldehyde/quaternary ammonium chloride lost significant biocidal activity after exposure to these same downhole temperatures. TTPC also showed excellent compatibility with anionic friction reducers. Once the efficacy and compatibility of TTPC was confirmed in lab tests, it was used on several multi-well fracs. Results of the flowback testing gave zero viable sulfate-reducing and acid-producing bacteria and ATP values of <100 pg/ml in several wells, indicating that TTPC was highly effective at controlling microbial contamination in the harsh field environment.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79356078","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Within tight reservoirs, gas is stored both as free gas contained in the pores and adsorbed gas on the rock matrix. Adsorbed gas exhibits liquid-like densities resulting in significantly more gas being stored on the rock surface. By having accurate adsorption/desorption data of injected and reservoir gases, one can acquire a better understanding of the true original gas in place, as well as how to maximize production through optimal enhanced gas recovery (EGR) techniques. The aim of this research is to measure the adsorption/desorption isotherms of single-component gases on activated carbon in a series of pressure steps up to 1500 psi. The experiments are conducted at varying temperatures to establish a wide array of isotherms. Temperatures are maintained through the use of a water bath. The obtained isothermal pressure data is modeled using the Gibbs sorption isotherm and the Langmuir mathematical model, the most popular and simplistic approach. Furthermore, by plotting pressure divided by adsorption capacity as a function of pressure, Langmuir parameters are determined. From the experiments, isothermal pressure data was able to be modeled using the Gibbs sorption isotherm and the Langmuir isotherm and Langmuir parameters were determined and compared. It was observed that decreasing temperature and increasing hydrocarbon molecular weight were the main contributing factors to higher sorption capacities of the single component gases. It is important to quantify both adsorption and desorption processes because in EGR techniques such as cyclic solvent injection (CSI) injected gas is competitively adsorbing onto the rock, causing the adsorbed reservoir gas to be displaced, desorb, and subsequently be produced. Due to the aforementioned irreversibilities, by using adsorption metrics to quantify the amount of gas desorbed within the reservoir, gas production may be overestimated. To date, most adsorption/desorption experimental work has been conducted on methane, carbon dioxide, and nitrogen. This research aims to expand on previous literature by performing adsorption/desorption experiments on higher chain hydrocarbons, such as ethane and propane. By doing so, CSI EGR schemes can be more meticulously modeled as the inclusion of higher chain hydrocarbons allows for the model sorption inputs to be more representative of typical unconventional reservoir gas. This in turn will allow for more accurate production forecasting, helping minimize the financial risk of costly EGR projects.
{"title":"An Experimental Study of Single Component Adsorption/Desorption Isotherms","authors":"Jeremy Wolf, S. Maaref, B. Tutolo, A. Kantzas","doi":"10.2118/208920-ms","DOIUrl":"https://doi.org/10.2118/208920-ms","url":null,"abstract":"\u0000 Within tight reservoirs, gas is stored both as free gas contained in the pores and adsorbed gas on the rock matrix. Adsorbed gas exhibits liquid-like densities resulting in significantly more gas being stored on the rock surface. By having accurate adsorption/desorption data of injected and reservoir gases, one can acquire a better understanding of the true original gas in place, as well as how to maximize production through optimal enhanced gas recovery (EGR) techniques.\u0000 The aim of this research is to measure the adsorption/desorption isotherms of single-component gases on activated carbon in a series of pressure steps up to 1500 psi. The experiments are conducted at varying temperatures to establish a wide array of isotherms. Temperatures are maintained through the use of a water bath. The obtained isothermal pressure data is modeled using the Gibbs sorption isotherm and the Langmuir mathematical model, the most popular and simplistic approach. Furthermore, by plotting pressure divided by adsorption capacity as a function of pressure, Langmuir parameters are determined.\u0000 From the experiments, isothermal pressure data was able to be modeled using the Gibbs sorption isotherm and the Langmuir isotherm and Langmuir parameters were determined and compared. It was observed that decreasing temperature and increasing hydrocarbon molecular weight were the main contributing factors to higher sorption capacities of the single component gases. It is important to quantify both adsorption and desorption processes because in EGR techniques such as cyclic solvent injection (CSI) injected gas is competitively adsorbing onto the rock, causing the adsorbed reservoir gas to be displaced, desorb, and subsequently be produced. Due to the aforementioned irreversibilities, by using adsorption metrics to quantify the amount of gas desorbed within the reservoir, gas production may be overestimated.\u0000 To date, most adsorption/desorption experimental work has been conducted on methane, carbon dioxide, and nitrogen. This research aims to expand on previous literature by performing adsorption/desorption experiments on higher chain hydrocarbons, such as ethane and propane. By doing so, CSI EGR schemes can be more meticulously modeled as the inclusion of higher chain hydrocarbons allows for the model sorption inputs to be more representative of typical unconventional reservoir gas. This in turn will allow for more accurate production forecasting, helping minimize the financial risk of costly EGR projects.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88975626","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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