I. M. Carraretto, D. Pari, D. Fasani, A. Lucchini, M. Guilizzoni, L. Colombo
One of the most critical issues in the oil and gas industry is the dewatering of the pipelines used for natural gas transportation, and foam injection seems to be a prominent solution. This work has two goals: The main one concerns the development of an optical tool to measure the liquid holdup in foamy flows and perform the flow regime characterization, whereas the secondary goal is to quantify the effectiveness of surfactant injection in reducing the liquid loading. In this paper, we present the results of an experimental campaign aimed at the characterization of gas-liquid-foam flows in a horizontal pipe. Initially, liquid loading measurements for gas and liquid superficial velocities, ranging from 0.41 to 2.30 m/s and from 0.03 to 0.06 m/s, respectively, were performed by means of a specifically developed optical method. For each liquid superficial velocity, the minimum liquid holdup was found to lie in the proximity of the boundary between plug and stratified flow regime, with a superficial gas velocity between 0.44 and 0.90 m/s. Hence, the plug flow region corresponds to the best operating condition to perform the pipeline dewatering procedure. Moreover, the drift-flux model usually adopted for ordinary two-phasegas-liquid flows seems to fit well with the measured values of void fraction.
{"title":"Holdup Measurements of Aqueous Foam Flows and Flow Regime Characterization through Image Processing","authors":"I. M. Carraretto, D. Pari, D. Fasani, A. Lucchini, M. Guilizzoni, L. Colombo","doi":"10.2118/205522-PA","DOIUrl":"https://doi.org/10.2118/205522-PA","url":null,"abstract":"\u0000 One of the most critical issues in the oil and gas industry is the dewatering of the pipelines used for natural gas transportation, and foam injection seems to be a prominent solution. This work has two goals: The main one concerns the development of an optical tool to measure the liquid holdup in foamy flows and perform the flow regime characterization, whereas the secondary goal is to quantify the effectiveness of surfactant injection in reducing the liquid loading. In this paper, we present the results of an experimental campaign aimed at the characterization of gas-liquid-foam flows in a horizontal pipe. Initially, liquid loading measurements for gas and liquid superficial velocities, ranging from 0.41 to 2.30 m/s and from 0.03 to 0.06 m/s, respectively, were performed by means of a specifically developed optical method. For each liquid superficial velocity, the minimum liquid holdup was found to lie in the proximity of the boundary between plug and stratified flow regime, with a superficial gas velocity between 0.44 and 0.90 m/s. Hence, the plug flow region corresponds to the best operating condition to perform the pipeline dewatering procedure. Moreover, the drift-flux model usually adopted for ordinary two-phasegas-liquid flows seems to fit well with the measured values of void fraction.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"61 18","pages":"1-9"},"PeriodicalIF":1.2,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41330832","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}
G. S. Ramos, M. Pinto, E. Souza, G. B. Machado, G. G. R. D. Castro
As oil and gas exploration goes toward deeper fields in the Brazilian industry scenario, offloading operations emerge as the most viable option to drain production. However, these operations demand expensive resources, such as shuttle tankers and support boats; operational risks, which despite being managed, limited, and mitigated to be as low as reasonably possible, are still present in some stages (i.e., ship’s approximation to the oil rig, mooring, hose connection, and so forth); and environment limiting parameters (i.e., wave height, surface-current direction, wind speed and direction, and so forth). Therefore, in this paper, we propose using unmanned aerial vehicles (UAVs) in an autonomous mode to carry out the messenger line from the shuttle tanker to the floating, production, storage, and offloading (FPSO) unit or the floating storage and offloading unit (FSO) instead of line-handling (LH) boats (for conventional operations that use those resources) or the messenger-cable-launching guns (for dynamic positioning operations). This represents a viable alternative solution to reducing costs and risks in these tasks and a possibility to eliminate some meteorologic and oceanographic limiting conditions to operations, because the UAV will be susceptible only to wind conditions, and not to sea and visibility conditions, like LHs are. We present the simulated results of the proposed methodology using a robotic operating system (ROS) and the economic gain [derived from cash-flow-cost reducing of operations, payoff time of the investment, net present value (NPV), and internal rate of return] of applying this technology, evaluating its use in a realistic scenario based on a real deepwater oil field in Brazil. The developed controller behaves very well, and simulations showed robust results. In addition, the economic study presents the proposal’s attractiveness.
{"title":"Technical and Economic Feasibility Study for Implementing a Novel Mooring-Assisting Methodology in Offloading Operations Using Autonomous Unmanned Aerial Vehicles","authors":"G. S. Ramos, M. Pinto, E. Souza, G. B. Machado, G. G. R. D. Castro","doi":"10.2118/205524-pa","DOIUrl":"https://doi.org/10.2118/205524-pa","url":null,"abstract":"\u0000 As oil and gas exploration goes toward deeper fields in the Brazilian industry scenario, offloading operations emerge as the most viable option to drain production. However, these operations demand expensive resources, such as shuttle tankers and support boats; operational risks, which despite being managed, limited, and mitigated to be as low as reasonably possible, are still present in some stages (i.e., ship’s approximation to the oil rig, mooring, hose connection, and so forth); and environment limiting parameters (i.e., wave height, surface-current direction, wind speed and direction, and so forth). Therefore, in this paper, we propose using unmanned aerial vehicles (UAVs) in an autonomous mode to carry out the messenger line from the shuttle tanker to the floating, production, storage, and offloading (FPSO) unit or the floating storage and offloading unit (FSO) instead of line-handling (LH) boats (for conventional operations that use those resources) or the messenger-cable-launching guns (for dynamic positioning operations). This represents a viable alternative solution to reducing costs and risks in these tasks and a possibility to eliminate some meteorologic and oceanographic limiting conditions to operations, because the UAV will be susceptible only to wind conditions, and not to sea and visibility conditions, like LHs are. We present the simulated results of the proposed methodology using a robotic operating system (ROS) and the economic gain [derived from cash-flow-cost reducing of operations, payoff time of the investment, net present value (NPV), and internal rate of return] of applying this technology, evaluating its use in a realistic scenario based on a real deepwater oil field in Brazil. The developed controller behaves very well, and simulations showed robust results. In addition, the economic study presents the proposal’s attractiveness.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48157948","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}
V. Azari, O. Vazquez, S. Baraka-Lokmane, E. Mackay, Stuart Brice
Scale inhibitor (SI) squeeze treatments are one of the most common techniques to prevent downhole scale formation. In this paper, we present the optimization of treatment design for multiple wells included in offshore campaigns. Two offshore fields with 8 and 12 production wells in west Africa were considered that are separately treated via yearly squeeze campaigns. The wells included in each campaign are treated in a single trip of the supply vessel. Based on the storage capacity of the vessel, the available volume of SI onboard should be optimally allocated to each of the wells (having different properties and water production rates), so that they are all protected from scaling for 1 year until the next campaign is carried out. A hybrid optimization methodology was applied to optimize the squeeze campaign design. The gradient descent (GD) algorithm was first applied to derive the squeeze “isolifetime proxies” related to each well. Each proxy includes all the possible squeeze designs that result in 365 days of squeeze lifetime in the well. Using these proxies, any combination of wells’ squeeze designs could be nominated as the campaign design, because that would result in treating all wells until the next campaign. The multiobjective particle swarm optimization (MOPSO) technique was implemented to optimize the campaign design by simultaneously minimizing the total SI volume and the total injection time for the whole campaign. Minimizing the total pumping time would consequently minimize the deferred oil volume and the total cost of squeezes in the field. Finally, the Pareto Front was identified for each field, showing the most optimum campaign designs. The Pareto Front was shown to be a valuable tool for the operator to make a trade-off between the size of the vessel and the injection time; that is, to use a bigger vessel to transport more inhibitor to the wells or to use a smaller one but for a longer time to inject more water during the squeeze treatments in the field. A cost analysis was performed to identify the most optimum deployment plan providing the most optimum inhibitor allocation strategy, including the optimum inhibitor volume and the optimum injection time for each campaign.
{"title":"Full-Field Optimization of Offshore Squeeze Campaigns in Total Gulf of Guinea Fields","authors":"V. Azari, O. Vazquez, S. Baraka-Lokmane, E. Mackay, Stuart Brice","doi":"10.2118/204384-PA","DOIUrl":"https://doi.org/10.2118/204384-PA","url":null,"abstract":"\u0000 Scale inhibitor (SI) squeeze treatments are one of the most common techniques to prevent downhole scale formation. In this paper, we present the optimization of treatment design for multiple wells included in offshore campaigns. Two offshore fields with 8 and 12 production wells in west Africa were considered that are separately treated via yearly squeeze campaigns. The wells included in each campaign are treated in a single trip of the supply vessel. Based on the storage capacity of the vessel, the available volume of SI onboard should be optimally allocated to each of the wells (having different properties and water production rates), so that they are all protected from scaling for 1 year until the next campaign is carried out. A hybrid optimization methodology was applied to optimize the squeeze campaign design.\u0000 The gradient descent (GD) algorithm was first applied to derive the squeeze “isolifetime proxies” related to each well. Each proxy includes all the possible squeeze designs that result in 365 days of squeeze lifetime in the well. Using these proxies, any combination of wells’ squeeze designs could be nominated as the campaign design, because that would result in treating all wells until the next campaign. The multiobjective particle swarm optimization (MOPSO) technique was implemented to optimize the campaign design by simultaneously minimizing the total SI volume and the total injection time for the whole campaign. Minimizing the total pumping time would consequently minimize the deferred oil volume and the total cost of squeezes in the field.\u0000 Finally, the Pareto Front was identified for each field, showing the most optimum campaign designs. The Pareto Front was shown to be a valuable tool for the operator to make a trade-off between the size of the vessel and the injection time; that is, to use a bigger vessel to transport more inhibitor to the wells or to use a smaller one but for a longer time to inject more water during the squeeze treatments in the field. A cost analysis was performed to identify the most optimum deployment plan providing the most optimum inhibitor allocation strategy, including the optimum inhibitor volume and the optimum injection time for each campaign.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-15"},"PeriodicalIF":1.2,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42984527","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}
Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil/air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump. A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-in. casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 rev/min. Gas volume fractions (GVFs) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions. The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 rev/min, maximum pump delivery is approximately 190 and 330 B/D of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to approximately 5.5 psi at 200 rev/min and 15 psi at 350 rev/min. For the 200 to 350 rev/min speed range, volumetric efficiencies varied from 30 to 73%, whereas the electric power input varied from 145 to 191 W. When pumping oil/air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 rev/min. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32 to 53% for the 300 to 350 rev/min speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump. This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas/liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas/liquid mixtures in the oil and gas industry.
{"title":"Physical Performance Testing of a Prototype Gerotor Pump Operating in Liquid and Gas/Liquid Conditions","authors":"C. Ejim, Xiao Jinjiang, Lanre Oshinowo","doi":"10.2118/203407-PA","DOIUrl":"https://doi.org/10.2118/203407-PA","url":null,"abstract":"\u0000 Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil/air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump.\u0000 A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-in. casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 rev/min. Gas volume fractions (GVFs) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions.\u0000 The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 rev/min, maximum pump delivery is approximately 190 and 330 B/D of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to approximately 5.5 psi at 200 rev/min and 15 psi at 350 rev/min. For the 200 to 350 rev/min speed range, volumetric efficiencies varied from 30 to 73%, whereas the electric power input varied from 145 to 191 W. When pumping oil/air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 rev/min. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32 to 53% for the 300 to 350 rev/min speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump.\u0000 This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas/liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas/liquid mixtures in the oil and gas industry.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-13"},"PeriodicalIF":1.2,"publicationDate":"2021-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48080965","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. Alzahabi, A. Trindade, A. Kamel, A. Harouaka, W. Baustian, C. Campbell
One of the enduring pieces of the jigsaw puzzle for all unconventional plays is drawdown (DD), a technique for attaining optimal return on investment. Assessment of the DD from producing wells in unconventional resources poses unique challenges to operators; among them the fact that many operators are reluctant to reveal the production, pressure, and completion data required. In addition to multiple factors, various completion and spacing parameters add to the complexity of the problem. This work aims to determine the optimum DD strategy. Several DD trials were implemented within the Anadarko Basin in combination with various completion strategies. Privately obtained production and completion data were analyzed and combined with well log analysis in conjunction with data analytics tools. A case study is presented that explores a new strategy for DD producing wells within the Anadarko Basin to optimize a return on investment. We use scatter-plot smoothing to develop a predictive relationship between DD and two dependent variables—estimated ultimate recovery (EUR) and initial production (IP) for 180 days of oil—and introduce a model that evaluates horizontal well production variables based on DD. Key data were estimated using reservoir and production variables. The data analytics suggested the optimal DD value of 53 psi/D for different reservoirs within the Anadarko Basin. This result may give professionals additional insight into more fully understanding the Anadarko Basin. Through these optimal ranges, we hope to gain a more complete understanding of the best way to DD wells when they are drilled simultaneously. Our discoveries and workflow within the Woodford and Mayes Formations may be applied to various plays and formations across the unconventional play spectrum. Optimal DD techniques in unconventional reservoirs could add billions of dollars in revenue to a company’s portfolio and dramatically increase the rate of return, as well as offer a new understanding of the respective producing reservoirs.
{"title":"Optimal Drawdown for Woodford and Mayes in the Anadarko Basin Using Data Analytics","authors":"A. Alzahabi, A. Trindade, A. Kamel, A. Harouaka, W. Baustian, C. Campbell","doi":"10.2118/201660-PA","DOIUrl":"https://doi.org/10.2118/201660-PA","url":null,"abstract":"\u0000 One of the enduring pieces of the jigsaw puzzle for all unconventional plays is drawdown (DD), a technique for attaining optimal return on investment. Assessment of the DD from producing wells in unconventional resources poses unique challenges to operators; among them the fact that many operators are reluctant to reveal the production, pressure, and completion data required. In addition to multiple factors, various completion and spacing parameters add to the complexity of the problem. This work aims to determine the optimum DD strategy. Several DD trials were implemented within the Anadarko Basin in combination with various completion strategies. Privately obtained production and completion data were analyzed and combined with well log analysis in conjunction with data analytics tools. A case study is presented that explores a new strategy for DD producing wells within the Anadarko Basin to optimize a return on investment. We use scatter-plot smoothing to develop a predictive relationship between DD and two dependent variables—estimated ultimate recovery (EUR) and initial production (IP) for 180 days of oil—and introduce a model that evaluates horizontal well production variables based on DD. Key data were estimated using reservoir and production variables. The data analytics suggested the optimal DD value of 53 psi/D for different reservoirs within the Anadarko Basin. This result may give professionals additional insight into more fully understanding the Anadarko Basin. Through these optimal ranges, we hope to gain a more complete understanding of the best way to DD wells when they are drilled simultaneously. Our discoveries and workflow within the Woodford and Mayes Formations may be applied to various plays and formations across the unconventional play spectrum. Optimal DD techniques in unconventional reservoirs could add billions of dollars in revenue to a company’s portfolio and dramatically increase the rate of return, as well as offer a new understanding of the respective producing reservoirs.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":"1-11"},"PeriodicalIF":1.2,"publicationDate":"2021-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43971852","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}
Fracture packing is a well-known completion technique used in the hydraulic fracturing of low-permeability reservoirs. As much as fracture packs are very effective, the proppant-pack permeability damage formed from particle intrusion reduces that effectiveness because it causes low well productivity. It is important to address the issue of permeability damage caused by formation-particle intrusion. An analytical model was developed in this study to predict the permeability of proppant packs in hydraulic fractures with consideration of different levels of invasion damage of formation sand. The accuracy of the model was verified by model comparison with data from the Eagle Ford Shale field. The model result shows that for the Eagle Ford field and the corresponding proppant size used, three blocking levels were achieved that correspond to high proppant-pack permeability. Three case studies were considered in this study: California sand, Gulf Coast sand, and South China Sea silt. The proppant-pack permeability damage was calculated using the analytical model for three levels of invasion for all case studies. The results from applying the analytical model on the three case studies showed the amount of invasion that is possible in each sand according to the proppant size used. The level of invasion is a factor of the sand distribution and the initial proppant size chosen. More analysis showed that for two of the case studies, only Levels 1 and 2 blockings can develop, while for the last case study, three blocking levels considered can develop. This study, for the first time, gives an insight into how selecting the optimal proppant size can improve sand-control performance while enhancing fracture conductivity.
{"title":"A Mathematical Model for Estimating Fracture Permeability with Invasion Damage of Formation Sand","authors":"T. A. Timiyan, B. Guo","doi":"10.2118/205509-PA","DOIUrl":"https://doi.org/10.2118/205509-PA","url":null,"abstract":"\u0000 Fracture packing is a well-known completion technique used in the hydraulic fracturing of low-permeability reservoirs. As much as fracture packs are very effective, the proppant-pack permeability damage formed from particle intrusion reduces that effectiveness because it causes low well productivity. It is important to address the issue of permeability damage caused by formation-particle intrusion. An analytical model was developed in this study to predict the permeability of proppant packs in hydraulic fractures with consideration of different levels of invasion damage of formation sand. The accuracy of the model was verified by model comparison with data from the Eagle Ford Shale field. The model result shows that for the Eagle Ford field and the corresponding proppant size used, three blocking levels were achieved that correspond to high proppant-pack permeability. Three case studies were considered in this study: California sand, Gulf Coast sand, and South China Sea silt. The proppant-pack permeability damage was calculated using the analytical model for three levels of invasion for all case studies. The results from applying the analytical model on the three case studies showed the amount of invasion that is possible in each sand according to the proppant size used. The level of invasion is a factor of the sand distribution and the initial proppant size chosen. More analysis showed that for two of the case studies, only Levels 1 and 2 blockings can develop, while for the last case study, three blocking levels considered can develop. This study, for the first time, gives an insight into how selecting the optimal proppant size can improve sand-control performance while enhancing fracture conductivity.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-11"},"PeriodicalIF":1.2,"publicationDate":"2021-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42236722","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}
Uncertainties regarding the factors that influence asphaltene deposition in porous media (e.g., those resulting from oil composition, rock properties, and rock/fluid interaction) strongly affect the prediction of important variables, such as oil production. Besides, some aspects of these predictions are stochastic processes, such as the aggregation phenomenon of asphaltene precipitates. For this reason, a well-defined output from an asphaltene-deposition model might not be feasible. Instead of this, obtaining the probability distribution of important outputs (e.g., permeability reduction and oil production) should be the objective of rigorous modeling of this phenomenon. This probability distribution would support the design of a risk-based policy for the prevention and mitigation of asphaltene deposition. In this paper we aim to present a new approach to assessing the risk of formation damage caused by asphaltene deposition using Monte Carlo simulations. Using this approach, the probability-distribution function of the permeability reduction was obtained. To connect this information to a parameter more related to economic concepts, the probability distribution of the damage ratio (DR) was also calculated, which is the fraction of production loss caused by formation damage. A hypothetical scenario involving a decision in the asphaltene-prevention policy is presented as an application of the method. A novel approach to model the prevention of asphaltene aggregation using inhibitors has been proposed and successfully applied in this scenario.
{"title":"Monte Carlo Risk Assessment of Formation Damage Caused by Asphaltene Deposition","authors":"A. S. Carvalhal, G. Costa, S. V. D. Melo","doi":"10.2118/205510-PA","DOIUrl":"https://doi.org/10.2118/205510-PA","url":null,"abstract":"\u0000 Uncertainties regarding the factors that influence asphaltene deposition in porous media (e.g., those resulting from oil composition, rock properties, and rock/fluid interaction) strongly affect the prediction of important variables, such as oil production. Besides, some aspects of these predictions are stochastic processes, such as the aggregation phenomenon of asphaltene precipitates. For this reason, a well-defined output from an asphaltene-deposition model might not be feasible. Instead of this, obtaining the probability distribution of important outputs (e.g., permeability reduction and oil production) should be the objective of rigorous modeling of this phenomenon. This probability distribution would support the design of a risk-based policy for the prevention and mitigation of asphaltene deposition. In this paper we aim to present a new approach to assessing the risk of formation damage caused by asphaltene deposition using Monte Carlo simulations. Using this approach, the probability-distribution function of the permeability reduction was obtained. To connect this information to a parameter more related to economic concepts, the probability distribution of the damage ratio (DR) was also calculated, which is the fraction of production loss caused by formation damage. A hypothetical scenario involving a decision in the asphaltene-prevention policy is presented as an application of the method. A novel approach to model the prevention of asphaltene aggregation using inhibitors has been proposed and successfully applied in this scenario.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-8"},"PeriodicalIF":1.2,"publicationDate":"2021-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43234402","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. Demayo, Nevil Herbert, Dulce M. Hernandez, Jana J. Hendricks, Beberly Velasquez, David Cappello, Ian Creelman
This paper outlines one of the first efforts by a major oil and gas company to build a net-exporting, behind-the-meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field. The 29 MWAC (35 MWDC) Lost Hills solar plant in Lost Hills, California, USA, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 TWh of solar energy over 20 years to the field’s oil and gas production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride emissions, another potent greenhouse gas (GHG). Before the solar project, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California’s Low Carbon Fuel Standard (LCFS) and revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses and reduce its carbon intensity, while also generating LCFS credits. The solar plant was designed to power the field during the day and export excess power to the grid to help offset nighttime electricity purchases. It operates under a power purchase agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field’s energy needs. Future plans include incorporating 20 MWh of lithium-ion batteries, direct current (DC)–coupled with the solar inverters. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power and energy storage provide a robust renewable energy solution. This project will generate multiple cobenefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Conceivably, the Lost Hills solar project can be a model for similar future projects in other oil fields, not only in California, but across the globe.
{"title":"Lost Hills Solar Project: Powering an Oil and Gas Field with California Sunshine","authors":"T. Demayo, Nevil Herbert, Dulce M. Hernandez, Jana J. Hendricks, Beberly Velasquez, David Cappello, Ian Creelman","doi":"10.2118/200839-MS","DOIUrl":"https://doi.org/10.2118/200839-MS","url":null,"abstract":"\u0000 This paper outlines one of the first efforts by a major oil and gas company to build a net-exporting, behind-the-meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field. The 29 MWAC (35 MWDC) Lost Hills solar plant in Lost Hills, California, USA, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 TWh of solar energy over 20 years to the field’s oil and gas production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride emissions, another potent greenhouse gas (GHG).\u0000 Before the solar project, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California’s Low Carbon Fuel Standard (LCFS) and revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses and reduce its carbon intensity, while also generating LCFS credits. The solar plant was designed to power the field during the day and export excess power to the grid to help offset nighttime electricity purchases. It operates under a power purchase agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field’s energy needs. Future plans include incorporating 20 MWh of lithium-ion batteries, direct current (DC)–coupled with the solar inverters. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power and energy storage provide a robust renewable energy solution.\u0000 This project will generate multiple cobenefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Conceivably, the Lost Hills solar project can be a model for similar future projects in other oil fields, not only in California, but across the globe.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2021-04-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47515713","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Karaaslan, G. K. Wong, Kevin Louis Soter, S. Hicking, M. Yousif
Well surveillance requires practical models to balance the reward of maximizing production with the risk of ramping up production too much, which damages the completion. In this paper we present a method to monitor and ramp up production for openhole standalone screen (OH-SAS) completion. The objective is to optimize production using pressure transient analyses to assess the completion impairment and failure risks during the production ramp-up process. The flux model incorporates filter-cake pinholes, which are formed from nonuniform deposition and cleanup of filter cake during drilling and completion operations. Pinholes cause concentrated fluxes and increase completion failure risks. The method comprises three components, which are (1) determine pinhole properties from laboratory tests, (2) relate completion pressure drop of production through pinholes to pressure transient analyses, and (3) distribute fluxes in the standalone screen wellbore. Examples are presented and show that the completion pressure drop as a function of flow rate is nonlinear and higher with pinholes than without pinholes. By not incorporating pinholes, operations can potentially limit ramp-up. Flux distribution examples show that the largest impingement or radial velocity is at the top section of screen. The axial annular flow velocity or scouring velocity is two orders of magnitude larger than the screen impingement velocity. An integrated flux surveillance method for OH-SAS completion is presented for field applications.
{"title":"A Well Flux Surveillance and Production Ramp-Up Method for Openhole Standalone Screen Completion","authors":"M. Karaaslan, G. K. Wong, Kevin Louis Soter, S. Hicking, M. Yousif","doi":"10.2118/201662-PA","DOIUrl":"https://doi.org/10.2118/201662-PA","url":null,"abstract":"\u0000 Well surveillance requires practical models to balance the reward of maximizing production with the risk of ramping up production too much, which damages the completion. In this paper we present a method to monitor and ramp up production for openhole standalone screen (OH-SAS) completion. The objective is to optimize production using pressure transient analyses to assess the completion impairment and failure risks during the production ramp-up process. The flux model incorporates filter-cake pinholes, which are formed from nonuniform deposition and cleanup of filter cake during drilling and completion operations. Pinholes cause concentrated fluxes and increase completion failure risks. The method comprises three components, which are (1) determine pinhole properties from laboratory tests, (2) relate completion pressure drop of production through pinholes to pressure transient analyses, and (3) distribute fluxes in the standalone screen wellbore. Examples are presented and show that the completion pressure drop as a function of flow rate is nonlinear and higher with pinholes than without pinholes. By not incorporating pinholes, operations can potentially limit ramp-up. Flux distribution examples show that the largest impingement or radial velocity is at the top section of screen. The axial annular flow velocity or scouring velocity is two orders of magnitude larger than the screen impingement velocity. An integrated flux surveillance method for OH-SAS completion is presented for field applications.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-18"},"PeriodicalIF":1.2,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44418196","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}
It is common to inject acidic stimulation fluids into oil-bearing carbonate formations to enhance well productivity. This process of matrix acidizing is designed to maximize the propagation of wormholes into the formation by optimizing the injection parameters, including acid-injection rate and volume. Previous studies have suggested that saturation conditions, permeability, heterogeneity, temperature, and pressure can significantly affect the design of matrix-acidizing treatments. However, laboratory studies’ results are inconsistent in their conclusions and are mostly limited to water-saturated cores. In this work, we designed a systematic experimental study to evaluate the impact of multiphase flow on the acidizing process when injecting 15 wt% hydrochloric acid (HCl) into crude-oil-saturated Indiana Limestone cores. The results reveal the following: Contrary to published literature for water-saturated cores, acidizing in partially oil-saturatedhigh-permeability cores at high pressure requires less acid volume than in low-permeability cores; lower-pressure acid injection results in more efficient wormhole propagation in low-permeability cores compared to high-pressure acid injection; acidizing in low- and high-permeability cores at low pressure leads to similar efficiency; and wormholing is more effective in partially oil-saturated cores, resulting in multiple parallel branches as compared to inefficient leakoff in water-saturatedcores.
{"title":"Quantifying the Effect of Multiphase Flow on Matrix Acidizing in Oil-Bearing Carbonate Formations","authors":"Mohamed Elsafih, M. Fahes","doi":"10.2118/205397-PA","DOIUrl":"https://doi.org/10.2118/205397-PA","url":null,"abstract":"\u0000 It is common to inject acidic stimulation fluids into oil-bearing carbonate formations to enhance well productivity. This process of matrix acidizing is designed to maximize the propagation of wormholes into the formation by optimizing the injection parameters, including acid-injection rate and volume. Previous studies have suggested that saturation conditions, permeability, heterogeneity, temperature, and pressure can significantly affect the design of matrix-acidizing treatments. However, laboratory studies’ results are inconsistent in their conclusions and are mostly limited to water-saturated cores. In this work, we designed a systematic experimental study to evaluate the impact of multiphase flow on the acidizing process when injecting 15 wt% hydrochloric acid (HCl) into crude-oil-saturated Indiana Limestone cores. The results reveal the following: Contrary to published literature for water-saturated cores, acidizing in partially oil-saturatedhigh-permeability cores at high pressure requires less acid volume than in low-permeability cores; lower-pressure acid injection results in more efficient wormhole propagation in low-permeability cores compared to high-pressure acid injection; acidizing in low- and high-permeability cores at low pressure leads to similar efficiency; and wormholing is more effective in partially oil-saturated cores, resulting in multiple parallel branches as compared to inefficient leakoff in water-saturatedcores.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"1 1","pages":"1-12"},"PeriodicalIF":1.2,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43659093","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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