Oil and gas will be the main part of our future energy sources, despite of emerging and expanding of renewable energies. Enhanced Oil Recovery (EOR) plays an important role in the future oil and gas industry as the conventional oil reserves will shrink. Heavy oil reservoirs will be the main target of EOR methods because of the high number of existing heavy oil reservoirs. Surfactants are the most efficient chemical EOR method for many unconventional reservoirs as previous studies suggest. The problem with this EOR method is that these projects have high costs and raised environmental concerns. Ionic liquids (ILs) are introduced as an alternative material to surfactants, however, the cost of their synthesis and purification processes are high. Besides, some of them are toxic and have non-biodegradable properties which limit their commercial usage. Recently, a new form of ILs produced and called Deep Eutectic Solvents (DESs). The discovered material is more affordable and environmentally friendly and hence, it is considered to be an alternative material for existing conventional ILs. DESs are cheap, easy to produce, non-toxic, reusable, bio-degradable, and environmentally friendly. These materials consist of two or more cheap and safe components which will form a eutectic mixture. The melting point of the final mixture is lower than its components. In this study, the effectiveness of DESs in the EOR is analysed and evaluated to consider it as a new injection material for chemical EOR. This material has specific properties which improve the efficiency of EOR processes. Some of the favourable properties are stable emulsion between phases, interfacial tension (IFT) reduction, wettability change, recovery enhancement, and avoiding formation damage which is discussed and analysed in this paper. Moreover, the cost of the process is hugely reduced compared with other chemical injection methods. As the result, the main factor for the recovery enhancement is wettability alteration and the chance of viscosity. Besides, only malonic and acid-based DESs formed emulsions with oil, and the other types of DESs did not show emulsification properties. The IFT value increased for heavy oil reservoirs, while for reservoirs with light/medium oil IFT was reduced. Furthermore, DESs did not show formation damage which is a bonus point for this method. As the final result, Choline Chloride Glycerol showed the best recovery with an extra 30% to the original production.
{"title":"Potential of Deep Eutectic Solvents in the Upstream Oil and Gas Industry","authors":"Z. Hamdi, Shaberdi Koshekov, M. Bataee","doi":"10.2118/214427-ms","DOIUrl":"https://doi.org/10.2118/214427-ms","url":null,"abstract":"\u0000 Oil and gas will be the main part of our future energy sources, despite of emerging and expanding of renewable energies. Enhanced Oil Recovery (EOR) plays an important role in the future oil and gas industry as the conventional oil reserves will shrink. Heavy oil reservoirs will be the main target of EOR methods because of the high number of existing heavy oil reservoirs. Surfactants are the most efficient chemical EOR method for many unconventional reservoirs as previous studies suggest. The problem with this EOR method is that these projects have high costs and raised environmental concerns. Ionic liquids (ILs) are introduced as an alternative material to surfactants, however, the cost of their synthesis and purification processes are high. Besides, some of them are toxic and have non-biodegradable properties which limit their commercial usage. Recently, a new form of ILs produced and called Deep Eutectic Solvents (DESs). The discovered material is more affordable and environmentally friendly and hence, it is considered to be an alternative material for existing conventional ILs. DESs are cheap, easy to produce, non-toxic, reusable, bio-degradable, and environmentally friendly. These materials consist of two or more cheap and safe components which will form a eutectic mixture. The melting point of the final mixture is lower than its components. In this study, the effectiveness of DESs in the EOR is analysed and evaluated to consider it as a new injection material for chemical EOR. This material has specific properties which improve the efficiency of EOR processes. Some of the favourable properties are stable emulsion between phases, interfacial tension (IFT) reduction, wettability change, recovery enhancement, and avoiding formation damage which is discussed and analysed in this paper. Moreover, the cost of the process is hugely reduced compared with other chemical injection methods. As the result, the main factor for the recovery enhancement is wettability alteration and the chance of viscosity. Besides, only malonic and acid-based DESs formed emulsions with oil, and the other types of DESs did not show emulsification properties. The IFT value increased for heavy oil reservoirs, while for reservoirs with light/medium oil IFT was reduced. Furthermore, DESs did not show formation damage which is a bonus point for this method. As the final result, Choline Chloride Glycerol showed the best recovery with an extra 30% to the original production.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"162 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122866620","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}
Armstrong Lee Agbaji, Reid Morrison, S. Lakshmanan
Various studies have shown that fossil fuels are the main driver for climate change and mitigating CO₂ emissions has been a major issue for the oil and gas industry. Directly and indirectly, the industry accounts for 42 percent of global emissions and it is now being referred to as ground zero for climate change. Pressure continues to mount from both the investor community and various governments who are demanding climate action and are proposing new requirements for businesses to publish specific details of how they will adapt and achieve net-zero by 2050. Leaders across the energy industry are now addressing these issues by incorporating ESG into their business. ESG issues cut across industries and lines of service, and these issues are ever evolving. Each industry has vastly different sources of emissions, therefore their means of decarbonization differ greatly. Understanding the emissions associated with oil and gas operations is crucial to evaluating and tracking the sustainability factors impacting the industry. This paper takes a deep dive into what sustainability and ESG looks like in oil and gas operations and addresses the key drivers of ESG in the oil industry. It details the ESG issues that are material to all sectors of the industry and provides valuable insights on how organizations can embed sustainable business practices into engineering design and business operations. It also addresses the specific challenges ESG poses to the industry, suggests a multi-pronged approach to tackle decarbonization, and looks at various opportunities that the wave of ESG activities present for the industry. Succeeding in business is no longer just about profitability, but about how companies perform on a variety of ESG-related issues. It is now a business imperative to undergo a sustainability transformation, and oil industry operations should be designed with sustainability in mind. Sustainability and ESG should be part of the industry’s DNA and should be integrated in all its activities. ESG issues represent the language of the future and addressing it will become as significant for the oil industry as digital transformation; not only because of its broad geographical footprint, but also its operations and assets, many of which are GHG emitters. ESG is not just a compliance exercise, it's a strategic decision. To meet the goals of the Paris Agreement, the oil industry should strive to become a net-zero GHG emitter. Without a net-zero story, it may realize that there might not be much interest in hearing the rest of its story. The net-zero equation is not yet solved, but it can be, with bold action and smart innovation. No other industry is better positioned to solve this than the oil and gas industry.
{"title":"ESG, Sustainability and Decarbonization: An Analysis of Strategies and Solutions for the Energy Industry","authors":"Armstrong Lee Agbaji, Reid Morrison, S. Lakshmanan","doi":"10.2118/214346-ms","DOIUrl":"https://doi.org/10.2118/214346-ms","url":null,"abstract":"Various studies have shown that fossil fuels are the main driver for climate change and mitigating CO₂ emissions has been a major issue for the oil and gas industry. Directly and indirectly, the industry accounts for 42 percent of global emissions and it is now being referred to as ground zero for climate change. Pressure continues to mount from both the investor community and various governments who are demanding climate action and are proposing new requirements for businesses to publish specific details of how they will adapt and achieve net-zero by 2050. Leaders across the energy industry are now addressing these issues by incorporating ESG into their business. ESG issues cut across industries and lines of service, and these issues are ever evolving. Each industry has vastly different sources of emissions, therefore their means of decarbonization differ greatly. Understanding the emissions associated with oil and gas operations is crucial to evaluating and tracking the sustainability factors impacting the industry. This paper takes a deep dive into what sustainability and ESG looks like in oil and gas operations and addresses the key drivers of ESG in the oil industry. It details the ESG issues that are material to all sectors of the industry and provides valuable insights on how organizations can embed sustainable business practices into engineering design and business operations. It also addresses the specific challenges ESG poses to the industry, suggests a multi-pronged approach to tackle decarbonization, and looks at various opportunities that the wave of ESG activities present for the industry. Succeeding in business is no longer just about profitability, but about how companies perform on a variety of ESG-related issues. It is now a business imperative to undergo a sustainability transformation, and oil industry operations should be designed with sustainability in mind. Sustainability and ESG should be part of the industry’s DNA and should be integrated in all its activities. ESG issues represent the language of the future and addressing it will become as significant for the oil industry as digital transformation; not only because of its broad geographical footprint, but also its operations and assets, many of which are GHG emitters. ESG is not just a compliance exercise, it's a strategic decision. To meet the goals of the Paris Agreement, the oil industry should strive to become a net-zero GHG emitter. Without a net-zero story, it may realize that there might not be much interest in hearing the rest of its story. The net-zero equation is not yet solved, but it can be, with bold action and smart innovation. No other industry is better positioned to solve this than the oil and gas industry.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114546986","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to investigate the estimation of layer permeability, skin, and inflow profile from observations of production-logging-tool (PLT) and/or distributed temperature sensing (DTS) for a multilayered system where the layers communicate only through the wellbore. To achieve this objective, we develop a thermal, transient coupled reservoir/wellbore simulator that numerically solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The simulator accounts for the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection effects for predicting the flow profiles across the wellbore. A comparison of the developed model with a commercial simulator is provided for the single-phase fluid flow of oil or geothermal brine from partially penetrating vertical or inclined wells with distinct fluid and formation properties. A sensitivity study on transient pressure, rate, and temperature profiles to identify the effect of the layer petrophysical properties and the layer thermophysical parameters is also conducted through synthetically generated test data sets from the developed simulator. In addition, nonlinear parameter estimation with the use of both profiles is shown to be useful to reveal permeability and skin information about individual layers. The results show that temperature transient data are more reflective of the properties of the near wellbore region, while wellbore pressures are determined more by average reservoir parameters. The simulator proves practical for designing a PLT test provided that limitations such as single-phase fluid flow having vertical or inclined well equipped with a thorough fluid characterization (EOS) are met. Such design tests may provide a good source for cross-checking PLT flow profiles and validating the fluid contributions from layers that are open to flow. It is often that the spinner of the field PLT tool does not operate properly at very low flow rates. Also, the spinner may fail to calculate and construct PLT plots accurately at very high flow rates. To the best of our knowledge, this is the first study that presents a coupled transient reservoir/wellbore model for predicting layer permeability, skin, and inflow profile of a well from observations of pressure, temperate, and/or rate data from production-logging-tools (PLTs) and/or distributed temperature sensing (DTS) fiber optic cables.
{"title":"Estimation of Permeability, Skin, and Inflow Profile in Multilayered Systems from Temperature Transient Data Using a Coupled Nonisothermal, Transient Reservoir and Wellbore Model","authors":"C. Alan, Murat Cinar, M. Onur","doi":"10.2118/214384-ms","DOIUrl":"https://doi.org/10.2118/214384-ms","url":null,"abstract":"\u0000 The objective of this paper is to investigate the estimation of layer permeability, skin, and inflow profile from observations of production-logging-tool (PLT) and/or distributed temperature sensing (DTS) for a multilayered system where the layers communicate only through the wellbore. To achieve this objective, we develop a thermal, transient coupled reservoir/wellbore simulator that numerically solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The simulator accounts for the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection effects for predicting the flow profiles across the wellbore. A comparison of the developed model with a commercial simulator is provided for the single-phase fluid flow of oil or geothermal brine from partially penetrating vertical or inclined wells with distinct fluid and formation properties. A sensitivity study on transient pressure, rate, and temperature profiles to identify the effect of the layer petrophysical properties and the layer thermophysical parameters is also conducted through synthetically generated test data sets from the developed simulator. In addition, nonlinear parameter estimation with the use of both profiles is shown to be useful to reveal permeability and skin information about individual layers. The results show that temperature transient data are more reflective of the properties of the near wellbore region, while wellbore pressures are determined more by average reservoir parameters. The simulator proves practical for designing a PLT test provided that limitations such as single-phase fluid flow having vertical or inclined well equipped with a thorough fluid characterization (EOS) are met. Such design tests may provide a good source for cross-checking PLT flow profiles and validating the fluid contributions from layers that are open to flow. It is often that the spinner of the field PLT tool does not operate properly at very low flow rates. Also, the spinner may fail to calculate and construct PLT plots accurately at very high flow rates. To the best of our knowledge, this is the first study that presents a coupled transient reservoir/wellbore model for predicting layer permeability, skin, and inflow profile of a well from observations of pressure, temperate, and/or rate data from production-logging-tools (PLTs) and/or distributed temperature sensing (DTS) fiber optic cables.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125451172","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 this paper, we propose a Control Volume Material Balance (CVMB) approach for proxy reservoir simulation and apply it to real-time flow diagnostics. Instead of utilizing a comprehensive reservoir simulator, it estimates the saturations distributions by mapping the mass difference between injected and produced fluids recorded at wells into 3D grid blocks. On this basis, we perform real-time flow diagnostics to evaluate the dynamic heterogeneity of the instantaneous displacement flow field which can be used for making effective and opportune decisions to improve oil recovery. CVMB solves the pressure and flow fields implicitly, and the transport equations explicitly. It incorporates 3D heterogenous rock properties. The fundamental idea of the CVMB method is to divide the 3D flow field into a series of 1D well-pair Control Volumes (CVs). A well-pair Control Volume is composed of grid blocks in the intersection of the sweep and drainage regions of the injector and producer. The fluid flow in and out of the 1D CV can only occur at the wells, and the in-situ fluid volumes are determined by the well flow rates and the well allocation factors. In each CV, we assume the displacement in the grid blocks is piston-like and follows the 1D order of ascending forward time-of-flight. The fluid saturation distributions are determined by defining the cut-off time-of-flight for the displacement front. We show how the CVMB method improves the pattern-based mass balance approaches in the following aspects: 1) enables real-time flow diagnostics in terms of the hydrocarbon dynamic Lorenz coefficient without a comprehensive reservoir simulator; 2) enhances the simplicity and extensibility of the pattern-based mass balance approach without mapping between grid blocks and streamlines; 3) reduces the smearing effects in conventional mass balance approach by defining 1D CVs using forward time-of-flight. The proposed CVMB method utilizes the historical well flow rates as the input to estimate the swept regions and its average saturation with remarkable efficiency and sufficient accuracy for real-time flow diagnostics.
{"title":"A Control Volume Material Balance Approach and Its Applications to Real-Time Flow Diagnostics","authors":"Nan Zhang, P. Andersen, Chunming Rong","doi":"10.2118/214428-ms","DOIUrl":"https://doi.org/10.2118/214428-ms","url":null,"abstract":"\u0000 In this paper, we propose a Control Volume Material Balance (CVMB) approach for proxy reservoir simulation and apply it to real-time flow diagnostics. Instead of utilizing a comprehensive reservoir simulator, it estimates the saturations distributions by mapping the mass difference between injected and produced fluids recorded at wells into 3D grid blocks. On this basis, we perform real-time flow diagnostics to evaluate the dynamic heterogeneity of the instantaneous displacement flow field which can be used for making effective and opportune decisions to improve oil recovery.\u0000 CVMB solves the pressure and flow fields implicitly, and the transport equations explicitly. It incorporates 3D heterogenous rock properties. The fundamental idea of the CVMB method is to divide the 3D flow field into a series of 1D well-pair Control Volumes (CVs). A well-pair Control Volume is composed of grid blocks in the intersection of the sweep and drainage regions of the injector and producer. The fluid flow in and out of the 1D CV can only occur at the wells, and the in-situ fluid volumes are determined by the well flow rates and the well allocation factors. In each CV, we assume the displacement in the grid blocks is piston-like and follows the 1D order of ascending forward time-of-flight. The fluid saturation distributions are determined by defining the cut-off time-of-flight for the displacement front.\u0000 We show how the CVMB method improves the pattern-based mass balance approaches in the following aspects: 1) enables real-time flow diagnostics in terms of the hydrocarbon dynamic Lorenz coefficient without a comprehensive reservoir simulator; 2) enhances the simplicity and extensibility of the pattern-based mass balance approach without mapping between grid blocks and streamlines; 3) reduces the smearing effects in conventional mass balance approach by defining 1D CVs using forward time-of-flight.\u0000 The proposed CVMB method utilizes the historical well flow rates as the input to estimate the swept regions and its average saturation with remarkable efficiency and sufficient accuracy for real-time flow diagnostics.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134602128","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 staggering vulnerability of most conventional energy sources has caused the need to diversify the energy mix for most countries, if not all with most recent issues. Subsequently, numerous countries are experiencing a surge in energy demand and are confronted with the need to meet this increase in energy demand with a response to be ‘clean energy’ at an affordable price. The scope of this paper focuses on defining the different drivers and strategies that developing countries are utilizing to transform their local and interconnected energy sector. For ‘developing’ countries, the primary (current-) focus is on the fundamental commitment for energy diversification (e.g., energy security) in order to achieve sustainable self-sufficient energy source/s that are less impacted by socio-economical or geo-political factors. Furthermore, in this paper, specifically, the case study of Albania will be explained and how its strategy aligns with the global energy transition pathway. Additionally, the paper explores new alternative energy sources; technologies that before were barely considered, and how/why they are being deployed for adoption.
{"title":"Energy Transition Strategies to Implement Energy Security of Natural Resources: Albania Case Study","authors":"Beso Buranaj Hoxha, Trim Ternava, Dafina Buçaj","doi":"10.2118/214356-ms","DOIUrl":"https://doi.org/10.2118/214356-ms","url":null,"abstract":"\u0000 The staggering vulnerability of most conventional energy sources has caused the need to diversify the energy mix for most countries, if not all with most recent issues. Subsequently, numerous countries are experiencing a surge in energy demand and are confronted with the need to meet this increase in energy demand with a response to be ‘clean energy’ at an affordable price.\u0000 The scope of this paper focuses on defining the different drivers and strategies that developing countries are utilizing to transform their local and interconnected energy sector. For ‘developing’ countries, the primary (current-) focus is on the fundamental commitment for energy diversification (e.g., energy security) in order to achieve sustainable self-sufficient energy source/s that are less impacted by socio-economical or geo-political factors. Furthermore, in this paper, specifically, the case study of Albania will be explained and how its strategy aligns with the global energy transition pathway. Additionally, the paper explores new alternative energy sources; technologies that before were barely considered, and how/why they are being deployed for adoption.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"84 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131648902","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}
Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids. The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl). An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.
{"title":"Paradigm Shift in Conventional Hydraulic Fracturing - Emerging Fracturing Techniques Using Thermochemical Fluids","authors":"A. Al-Ghamdi, M. Al-Jawad, M. Mahmoud","doi":"10.2118/214376-ms","DOIUrl":"https://doi.org/10.2118/214376-ms","url":null,"abstract":"\u0000 Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids.\u0000 The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl).\u0000 An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130545106","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}
Ingvild Mæland, Leen Alaeddine, H. M. Ånes, Shih-Kai Chen, O. Lødøen, F. Martinsen
Oseberg is a large offshore field in North Sea with 4 main installations and several subsea developments. Production started in 1988. The field is covering the BRENT group. The study focuses on the Oseberg C platform which produces from the northern area of the Oseberg Main field. The Oseberg C involves a low-pressure production project executed in the fall of 2022. The timing of when to eventually reduce the topside separation pressure even more, and/or stop or reduce stop gas injection and instead export the produced gas via an existing multiphase pipeline to the Field center will be investigated in this study. The main objective is to illustrate a workflow that allows revising the drainage strategy while simultaneously reducing scope 1 CO2 emissions to attain a low emissions reservoir management strategy along with minimizing the losses in reserves. Mitigating reserves losses will be studied through different sensitivities. Several factors must be considered when studying modifications in the drainage strategy. Well delivery potential, gas export pressure to the Field center and the gas capacity at Field center are all important boundary conditions. A reservoir simulation model is used to study the reservoir impact of lowered OSC inlet pressure and effect of stopping the gas injection at different dates. A set of scenarios capturing consistently reservoir simulation and topside models are designed to assess the optimal timing of when to stop gas injection on Oseberg C. The optimal timing is evaluated by considering reservoir recovery and CO2 emissions. Reserves evaluation is performed using a reservoir simulation model (ECLIPSE), and emission forecasts are performed using eCalc™ (Skjerve et al., 2022). eCalc™ is the name of a software tool for high-quality emission forecasting. eCalc™ allows the integration of subsurface and operational knowledge and calculates emission forecasts directly relating drainage strategy to operational strategies and process equipment. The emission sources change significantly with the drainage strategy assumptions leaving correlation models less suited. eCalc™ is using mechanistic models of the topside processes and therefore can predict the effects of large changes in the drainage strategy and topside process.
{"title":"Using eCalc™ for Designing a Low Emission Reservoir Drainage Strategy for Oseberg C","authors":"Ingvild Mæland, Leen Alaeddine, H. M. Ånes, Shih-Kai Chen, O. Lødøen, F. Martinsen","doi":"10.2118/214344-ms","DOIUrl":"https://doi.org/10.2118/214344-ms","url":null,"abstract":"\u0000 Oseberg is a large offshore field in North Sea with 4 main installations and several subsea developments. Production started in 1988. The field is covering the BRENT group. The study focuses on the Oseberg C platform which produces from the northern area of the Oseberg Main field. The Oseberg C involves a low-pressure production project executed in the fall of 2022. The timing of when to eventually reduce the topside separation pressure even more, and/or stop or reduce stop gas injection and instead export the produced gas via an existing multiphase pipeline to the Field center will be investigated in this study.\u0000 The main objective is to illustrate a workflow that allows revising the drainage strategy while simultaneously reducing scope 1 CO2 emissions to attain a low emissions reservoir management strategy along with minimizing the losses in reserves. Mitigating reserves losses will be studied through different sensitivities.\u0000 Several factors must be considered when studying modifications in the drainage strategy. Well delivery potential, gas export pressure to the Field center and the gas capacity at Field center are all important boundary conditions. A reservoir simulation model is used to study the reservoir impact of lowered OSC inlet pressure and effect of stopping the gas injection at different dates. A set of scenarios capturing consistently reservoir simulation and topside models are designed to assess the optimal timing of when to stop gas injection on Oseberg C. The optimal timing is evaluated by considering reservoir recovery and CO2 emissions.\u0000 Reserves evaluation is performed using a reservoir simulation model (ECLIPSE), and emission forecasts are performed using eCalc™ (Skjerve et al., 2022). eCalc™ is the name of a software tool for high-quality emission forecasting. eCalc™ allows the integration of subsurface and operational knowledge and calculates emission forecasts directly relating drainage strategy to operational strategies and process equipment. The emission sources change significantly with the drainage strategy assumptions leaving correlation models less suited. eCalc™ is using mechanistic models of the topside processes and therefore can predict the effects of large changes in the drainage strategy and topside process.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126489959","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}
Nils Langanke, T. Leblanc, A. Fadili, R. Hincapie, L. Ganzer
The properties of polymeric materials are commonly modified by adjusting the dispersity of the molecular weight distribution, since polymer properties are dominated by intermolecular interactions. We utilized this approach to alter the rheological behavior of polymer solutions for application sub-surface and other porous media flow. We correlate the molecular weight distributions with screen factor measurements and in-situ rheological behavior. Aqueous solutions were prepared using mixtures of partially hydrolyzed polyacrylamide (HPAM) having different molecular weights. The behaviour of the solutions was studied in single-phase flooding experiments using Bentheimer and Berea outcrops, as well as a glass-silicon-glass microfluidic device that mimics porous media. The in-situ rheological behavior determined from flooding experiments was monitored by differential pressure measurements. To improve data accuracy, the core flooding experimental set-up was equipped with multiple pressure sensors along the core. Polymer solutions of same shear viscosity but significantly different dispersities were utilized for the investigation. Elongational viscosities were determined by screen factor measurements. We show that the apparent viscosity during polymer injection is significantly altered for polymer solutions of same average molecular weight but different dispersity. Namely, the onset of shear thickening occurs at lower equivalent shear rates when dispersity is high. Furthermore, the flow of polymer solutions in porous media was correlated to screen factor measurements. This effect of the dispersity of the molecular weight distribution can be used to optimize polymer solution applications in porous materials.
{"title":"Flow of Viscoelastic Polymer Solutions in Porous Media: Influence of Molecular Weight and Dispersity","authors":"Nils Langanke, T. Leblanc, A. Fadili, R. Hincapie, L. Ganzer","doi":"10.2118/214386-ms","DOIUrl":"https://doi.org/10.2118/214386-ms","url":null,"abstract":"\u0000 The properties of polymeric materials are commonly modified by adjusting the dispersity of the molecular weight distribution, since polymer properties are dominated by intermolecular interactions. We utilized this approach to alter the rheological behavior of polymer solutions for application sub-surface and other porous media flow. We correlate the molecular weight distributions with screen factor measurements and in-situ rheological behavior. Aqueous solutions were prepared using mixtures of partially hydrolyzed polyacrylamide (HPAM) having different molecular weights. The behaviour of the solutions was studied in single-phase flooding experiments using Bentheimer and Berea outcrops, as well as a glass-silicon-glass microfluidic device that mimics porous media. The in-situ rheological behavior determined from flooding experiments was monitored by differential pressure measurements. To improve data accuracy, the core flooding experimental set-up was equipped with multiple pressure sensors along the core. Polymer solutions of same shear viscosity but significantly different dispersities were utilized for the investigation. Elongational viscosities were determined by screen factor measurements. We show that the apparent viscosity during polymer injection is significantly altered for polymer solutions of same average molecular weight but different dispersity. Namely, the onset of shear thickening occurs at lower equivalent shear rates when dispersity is high. Furthermore, the flow of polymer solutions in porous media was correlated to screen factor measurements. This effect of the dispersity of the molecular weight distribution can be used to optimize polymer solution applications in porous materials.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130657957","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}
District heating can be decarbonized by using low enthalpy geothermal heat. In this case study, water from a deep saline aquifer with a temperature of 90-110 °C is produced, heat extracted for district heating and the cold water re-injected into the aquifer. There are substantial subsurface uncertainties in the structure as well as porosity and permeability distribution of the saline aquifer that need to be addressed to optimize heat extraction under uncertainty. The deep saline aquifer characterization is based on 3D seismic and a limited number of wells. Hence, substantial uncertainty exists in porosity/permeability distribution and dynamic and thermal properties. To address the uncertainty, different geological concepts need to be evaluated and parameter ranges for geostatistical and poro-perm relationships need to be used. To cover the uncertainty range, we constructed 600 geological models all honoring the limited existing data. However, dynamically simulating all the geological models including the ranges for the thermal properties is usually too costly. We utilize a geo-screening workflow, which selects a subset of representative models based on dynamic (proxy) response, the workflow aims at keeping the same variability of the subset as for the full ensemble. This is achieved via a dimensionality reduction of the problem, by clustering of the models in multi-dimensional space. The centroids of these clusters are selected as representative models used for full-physics simulations to forecast heat extraction under uncertainty. To define a consistent method for selecting a representative subset of geologic realization we simulated the full ensemble and compared it to (i) subsets of different clustering approaches using static (heat in-place) and dynamic (tracer rate & flux pattern) proxy responses and (ii) subset sizes. The results of the workflow show that the tracer rate is a better metric for the selection of the cluster centroids compared with flux-pattern and in particular heat in place. For this case 20-40 geological realizations were sufficient to cover the uncertainty space for forecasting low enthalpy heat extraction. The suggested workflow allows for addressing the subsurface uncertainty in static and dynamic parameters making use of streamline simulation to reduce simulation costs. The resulting model ensemble can be used for field development planning of low enthalpy heat extraction under uncertainty.
{"title":"Forecasting Low Enthalpy Geothermal Heat Extraction from Saline Aquifers Under Uncertainty","authors":"M. Bayerl, M. Ebner, T. Clemens","doi":"10.2118/214413-ms","DOIUrl":"https://doi.org/10.2118/214413-ms","url":null,"abstract":"\u0000 District heating can be decarbonized by using low enthalpy geothermal heat. In this case study, water from a deep saline aquifer with a temperature of 90-110 °C is produced, heat extracted for district heating and the cold water re-injected into the aquifer. There are substantial subsurface uncertainties in the structure as well as porosity and permeability distribution of the saline aquifer that need to be addressed to optimize heat extraction under uncertainty.\u0000 The deep saline aquifer characterization is based on 3D seismic and a limited number of wells. Hence, substantial uncertainty exists in porosity/permeability distribution and dynamic and thermal properties. To address the uncertainty, different geological concepts need to be evaluated and parameter ranges for geostatistical and poro-perm relationships need to be used. To cover the uncertainty range, we constructed 600 geological models all honoring the limited existing data. However, dynamically simulating all the geological models including the ranges for the thermal properties is usually too costly.\u0000 We utilize a geo-screening workflow, which selects a subset of representative models based on dynamic (proxy) response, the workflow aims at keeping the same variability of the subset as for the full ensemble. This is achieved via a dimensionality reduction of the problem, by clustering of the models in multi-dimensional space. The centroids of these clusters are selected as representative models used for full-physics simulations to forecast heat extraction under uncertainty. To define a consistent method for selecting a representative subset of geologic realization we simulated the full ensemble and compared it to (i) subsets of different clustering approaches using static (heat in-place) and dynamic (tracer rate & flux pattern) proxy responses and (ii) subset sizes.\u0000 The results of the workflow show that the tracer rate is a better metric for the selection of the cluster centroids compared with flux-pattern and in particular heat in place. For this case 20-40 geological realizations were sufficient to cover the uncertainty space for forecasting low enthalpy heat extraction. The suggested workflow allows for addressing the subsurface uncertainty in static and dynamic parameters making use of streamline simulation to reduce simulation costs. The resulting model ensemble can be used for field development planning of low enthalpy heat extraction under uncertainty.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132738894","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}
Due to the maturity of water-flooded oil reservoirs, as a consequence of heterogeneity, fluids move preferentially through the most permeable layers, leaving large volumes of mobile oil remain unswept. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Droplet size distribution and porous media heterogeneity are the principal features that characterize displacement front uniformity. The intent of this work is therefore to provide a fundamental insight into number of factors may influence the dispersion flow in porous media. The workflow in this study is comprised of three stages. First, O/W dispersions with low oil concentrations were prepared and characterized. Second, a series of O/W dispersion injection experiments was conducted. The objective of this stage was to evaluate the distribution of retained oil droplets, pressure drop and permeability reduction in different sandstone core-plugs. Finally, a mathematical model based on the experimental setup was developed to describe the dynamics of O/W dispersion flow. Finite element method (FEM) was employed to numerically solve the governing equations. The experimental results revealed that the number and size of retained oil droplets decay with the core depth and correspondingly in the effluent. Verification of the numerical model was performed by comparing the pressure drop and permeability reduction to the results of analytical solutions. The model showed good validation with the experimental data. The numerical results were closely match those of the analytical solutions. The current work presents a potentially efficient method of modelling to describe the dispersion flow in porous media. However, for field applications, further improvement to the model complexity is required.
{"title":"Modeling of Oil-In-Water Dispersion Injection for Enhancing Displacement Front Uniformity in Water-Flooded Heterogeneous Reservoirs","authors":"N. Alahmed, I. Fjelde","doi":"10.2118/214454-ms","DOIUrl":"https://doi.org/10.2118/214454-ms","url":null,"abstract":"\u0000 Due to the maturity of water-flooded oil reservoirs, as a consequence of heterogeneity, fluids move preferentially through the most permeable layers, leaving large volumes of mobile oil remain unswept. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Droplet size distribution and porous media heterogeneity are the principal features that characterize displacement front uniformity. The intent of this work is therefore to provide a fundamental insight into number of factors may influence the dispersion flow in porous media. The workflow in this study is comprised of three stages. First, O/W dispersions with low oil concentrations were prepared and characterized. Second, a series of O/W dispersion injection experiments was conducted. The objective of this stage was to evaluate the distribution of retained oil droplets, pressure drop and permeability reduction in different sandstone core-plugs. Finally, a mathematical model based on the experimental setup was developed to describe the dynamics of O/W dispersion flow. Finite element method (FEM) was employed to numerically solve the governing equations. The experimental results revealed that the number and size of retained oil droplets decay with the core depth and correspondingly in the effluent. Verification of the numerical model was performed by comparing the pressure drop and permeability reduction to the results of analytical solutions. The model showed good validation with the experimental data. The numerical results were closely match those of the analytical solutions. The current work presents a potentially efficient method of modelling to describe the dispersion flow in porous media. However, for field applications, further improvement to the model complexity is required.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"149 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133914916","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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