S. Cartwright, S. Samoil, Bryson Lawton, Die Hu, Siqi Xie, Eric Wang, A. Aminbeidokhti, Seher Dawar, Rachel Dalton, Parisa Daeijavad, F. Maurer, Zhangxin Chen
Reservoir engineers must analyze and work with complicated 3D subsurface datasets. Extended reality (XR) hardware has undergone a renaissance in recent years and high-quality hardware is now widely available and affordable. What remains unsolved is how these technologies may be applied to improve reservoir engineering workflows, in order to help plan scenarios that reduce emissions and improve project efficiencies. We detail and discuss the first-year outcomes of an industry-academia collaboration which explores the application of XR technologies to a reservoir engineering workflow. A thorough review of the benefits of XR technology compared with conventional display and input devices was performed. The results of this were used to inform the design and development of a proof-of-concept visualization and analysis application for reservoir engineering workflows that utilizes the strengths of XR technology. Using this tool, representations of numerical reservoir models can be visualized and analyzed along with other data within virtual working spaces. User-driven interactions were designed for this application and implemented to be as intuitive and effective as possible. Networking capabilities were implemented so that multiple devices and multiple users may access any given virtual workspace, supporting both remote collaboration and cross-reality functionality. The features and design of the application were all developed with the intention of directly supporting the visualization and analysis of reservoir data. The benefits provided by utilizing XR technology include increased working space, improved spatial perception, and more intuitive user interaction. Features such as multi-model visualization, integration of 2D information visualization, data analysis features, and several different filtering techniques were developed to further enhance reservoir engineering workflows. Additional features in development that are highly anticipated by our industrial partner include methods to better facilitate clear communication when working with data in groups, the integration of presentation and group-work modes, and enhancing workflows with AI-assisted tasks. Careful consideration went into designing interactions that were natural and intuitive, yet flexible and efficient when working within 3D virtual environments. The innovation demonstrated in this project contributes to advancing the Canadian energy industry to a new era of exciting new visual and interactive technologies, while ensuring that these technologies can be utilized to provide true value to real-world problems. The lessons learned and design insights gained from this project may be applied far beyond reservoir engineering to enhance workflows in any domain where analysis of complex scientific datasets is required.
{"title":"Enhancing Reservoir Engineering Workflows with Augmented and Virtual Reality","authors":"S. Cartwright, S. Samoil, Bryson Lawton, Die Hu, Siqi Xie, Eric Wang, A. Aminbeidokhti, Seher Dawar, Rachel Dalton, Parisa Daeijavad, F. Maurer, Zhangxin Chen","doi":"10.2118/208880-ms","DOIUrl":"https://doi.org/10.2118/208880-ms","url":null,"abstract":"\u0000 Reservoir engineers must analyze and work with complicated 3D subsurface datasets. Extended reality (XR) hardware has undergone a renaissance in recent years and high-quality hardware is now widely available and affordable. What remains unsolved is how these technologies may be applied to improve reservoir engineering workflows, in order to help plan scenarios that reduce emissions and improve project efficiencies. We detail and discuss the first-year outcomes of an industry-academia collaboration which explores the application of XR technologies to a reservoir engineering workflow.\u0000 A thorough review of the benefits of XR technology compared with conventional display and input devices was performed. The results of this were used to inform the design and development of a proof-of-concept visualization and analysis application for reservoir engineering workflows that utilizes the strengths of XR technology. Using this tool, representations of numerical reservoir models can be visualized and analyzed along with other data within virtual working spaces. User-driven interactions were designed for this application and implemented to be as intuitive and effective as possible. Networking capabilities were implemented so that multiple devices and multiple users may access any given virtual workspace, supporting both remote collaboration and cross-reality functionality. The features and design of the application were all developed with the intention of directly supporting the visualization and analysis of reservoir data.\u0000 The benefits provided by utilizing XR technology include increased working space, improved spatial perception, and more intuitive user interaction. Features such as multi-model visualization, integration of 2D information visualization, data analysis features, and several different filtering techniques were developed to further enhance reservoir engineering workflows. Additional features in development that are highly anticipated by our industrial partner include methods to better facilitate clear communication when working with data in groups, the integration of presentation and group-work modes, and enhancing workflows with AI-assisted tasks. Careful consideration went into designing interactions that were natural and intuitive, yet flexible and efficient when working within 3D virtual environments.\u0000 The innovation demonstrated in this project contributes to advancing the Canadian energy industry to a new era of exciting new visual and interactive technologies, while ensuring that these technologies can be utilized to provide true value to real-world problems. The lessons learned and design insights gained from this project may be applied far beyond reservoir engineering to enhance workflows in any domain where analysis of complex scientific datasets is required.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126239434","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 the past several decades, traditional decline curve analyses have been widely used as a quick and simple yet efficient method for reserve estimation and production forecasting. Several new models have been proposed since 2000s to address limitations of traditional decline models in shale and tight reservoirs especially multiple flow regimes and long-tail behavior of production profile which results in overestimating the reserve by the traditional models. Several of these newly proposed decline curve analysis (DCA) models are conservative and provide pessimistic reserve estimates. The main purpose of this work is to evaluate the application of six heavy-tailed probability density functions (PDFs) to approximate production in shale and tight reservoirs. A new class of DCA model suitable to capture the production decline trend in shale and tight reservoirs is examined using real and simulated production data. The proposed class of DCA has been demonstrated to predict production more accurately in tight and shale reservoirs especially when only limited data are available from wells with less than a few months of production history.
{"title":"A Novel Procedure for Analyzing Production Decline in Unconventional Reservoirs Using Probability Density Functions","authors":"Hamzeh Alimohammadi, Mehdi Sadeghi, Shengnan Chen","doi":"10.2118/208909-ms","DOIUrl":"https://doi.org/10.2118/208909-ms","url":null,"abstract":"\u0000 In the past several decades, traditional decline curve analyses have been widely used as a quick and simple yet efficient method for reserve estimation and production forecasting. Several new models have been proposed since 2000s to address limitations of traditional decline models in shale and tight reservoirs especially multiple flow regimes and long-tail behavior of production profile which results in overestimating the reserve by the traditional models. Several of these newly proposed decline curve analysis (DCA) models are conservative and provide pessimistic reserve estimates.\u0000 The main purpose of this work is to evaluate the application of six heavy-tailed probability density functions (PDFs) to approximate production in shale and tight reservoirs. A new class of DCA model suitable to capture the production decline trend in shale and tight reservoirs is examined using real and simulated production data. The proposed class of DCA has been demonstrated to predict production more accurately in tight and shale reservoirs especially when only limited data are available from wells with less than a few months of production history.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131481441","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}
Blair J. MacDougall, Phil Nash, Bruce Doyle, Joshua Hudson, Rick Murphy, Justin Meyers
The offshore Oil and Gas industry continues to explore and develop oil and gas fields using installations powered by generators burning either natural gas or marine gas oil (MGO), similar to diesel. There is increasing pressure on the industry to explore and produce hydrocarbons responsibly, cost effectively and with the lowest emissions. By employing renewable sources of power, Waterford Energy Services Inc.'s (WESI) methodology provides a possible solution using Floating Offshore Wind Turbine (FOWT) to power offshore installations. Various methods are being proposed and developed to maintain production while bringing down overall greenhouse gas emissions (e.g. CO2, NOx, SOx). This paper outlines the methodology used for a conceptual design of a "Plug and Play" hybrid power solution in the Canadian Offshore Oil and Gas Industry. FOWTs are electrically connected to offshore installations such as Mobile Offshore Drilling Units (MODU), Floating Production Storage and Offloading (FPSO) and fixed production platforms in a harsh environment to replace large portions of the onboard power generation. Battery Energy Storage Systems (BESS) are incorporated to transition from wind power, increase efficiency, provide safety backup and enhance emissions reduction. The plan includes considerations for the optimal electrical and battery storage topology and the electrical equipment necessary to connect the FOWT Array to the offshore facility. For the purposes of this paper, a representative location was chosen offshore Newfoundland and Labrador, Canada to assess both local conditions and design requirements. WESI has evaluated additional global locations for this FOWT solution. The conceptual design considers the wind turbine power output and examines the components required to deliver the power to the installation's electrical system (e.g. transformers, batteries, switchgear, static and dynamic cables, disconnects, communications/monitoring and required safety systems). Although there have been incremental improvements in emissions via advancements in fuel standards and engine exhaust abatement modifications, the only approach to have a significant step-change improvement in emissions is through replacement of onboard power generation with renewable sources. It anticipated that the installations’ greenhouse gas (GHG) emissions can be reduced in excess of 70% by combining wind power and battery supplementation. Oil and Gas operations are ideal applications of this decarbonization approach, presenting an opportunity to mature FOWT technology which can readily adapt to other grid isolated applications such as Remote Communities, Aquaculture and near-shore Industries.
{"title":"Powering Offshore Installations with Wind Energy","authors":"Blair J. MacDougall, Phil Nash, Bruce Doyle, Joshua Hudson, Rick Murphy, Justin Meyers","doi":"10.2118/208979-ms","DOIUrl":"https://doi.org/10.2118/208979-ms","url":null,"abstract":"\u0000 The offshore Oil and Gas industry continues to explore and develop oil and gas fields using installations powered by generators burning either natural gas or marine gas oil (MGO), similar to diesel. There is increasing pressure on the industry to explore and produce hydrocarbons responsibly, cost effectively and with the lowest emissions. By employing renewable sources of power, Waterford Energy Services Inc.'s (WESI) methodology provides a possible solution using Floating Offshore Wind Turbine (FOWT) to power offshore installations. Various methods are being proposed and developed to maintain production while bringing down overall greenhouse gas emissions (e.g. CO2, NOx, SOx).\u0000 This paper outlines the methodology used for a conceptual design of a \"Plug and Play\" hybrid power solution in the Canadian Offshore Oil and Gas Industry. FOWTs are electrically connected to offshore installations such as Mobile Offshore Drilling Units (MODU), Floating Production Storage and Offloading (FPSO) and fixed production platforms in a harsh environment to replace large portions of the onboard power generation. Battery Energy Storage Systems (BESS) are incorporated to transition from wind power, increase efficiency, provide safety backup and enhance emissions reduction. The plan includes considerations for the optimal electrical and battery storage topology and the electrical equipment necessary to connect the FOWT Array to the offshore facility.\u0000 For the purposes of this paper, a representative location was chosen offshore Newfoundland and Labrador, Canada to assess both local conditions and design requirements. WESI has evaluated additional global locations for this FOWT solution.\u0000 The conceptual design considers the wind turbine power output and examines the components required to deliver the power to the installation's electrical system (e.g. transformers, batteries, switchgear, static and dynamic cables, disconnects, communications/monitoring and required safety systems).\u0000 Although there have been incremental improvements in emissions via advancements in fuel standards and engine exhaust abatement modifications, the only approach to have a significant step-change improvement in emissions is through replacement of onboard power generation with renewable sources. It anticipated that the installations’ greenhouse gas (GHG) emissions can be reduced in excess of 70% by combining wind power and battery supplementation.\u0000 Oil and Gas operations are ideal applications of this decarbonization approach, presenting an opportunity to mature FOWT technology which can readily adapt to other grid isolated applications such as Remote Communities, Aquaculture and near-shore Industries.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115439585","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}
J. Leem, I. H. Musa, C. Tan, M. F. Che Yusoff, Z. Zain, James Kear, D. Kasperczyk, Zuorong Chen, S. Salimzadeh
Leak-off characteristics during hydraulic fracturing operation are difficult to determine but yet critical in developing conventional and unconventional reservoirs with natural fractures and other weak structural planes (e.g. micro-faults, weak beddings). When hydraulic fractures interact with natural fractures, they will either be arrested or transect the natural fractures depend on the leak-off characteristic of the natural fractures. The effective leak-off characteristic in a naturally fractured reservoir is an essential input for hydraulic fracturing simulation and consequent completion design as well as reservoir simulation (e.g., dual porosity and dual permeability) and consequent production optimization. A novel method of estimating the effective leak-off characteristic in a naturally fractured reservoir is developed directly from hydraulic fracturing diagnostic tests such as minifrac and DFIT utilizing eXtended Finite Element Method (XFEM)-based 3D hydraulic fracturing model. Complex behaviors of hydraulic fractures interacting with natural fractures are simulated in the XFEM-based hydraulic fracturing model and history-matched with minifrac/DFIT data (i.e., treating pressure), in order to estimate effective leak-off characteristics of naturally fractured reservoirs.
{"title":"Estimating Leak-Off Characteristics Due to Hydraulic Fracture and Natural Fracture Interaction Utilizing XFEM-Based 3D Hydraulic Fracture Model","authors":"J. Leem, I. H. Musa, C. Tan, M. F. Che Yusoff, Z. Zain, James Kear, D. Kasperczyk, Zuorong Chen, S. Salimzadeh","doi":"10.2118/208896-ms","DOIUrl":"https://doi.org/10.2118/208896-ms","url":null,"abstract":"\u0000 Leak-off characteristics during hydraulic fracturing operation are difficult to determine but yet critical in developing conventional and unconventional reservoirs with natural fractures and other weak structural planes (e.g. micro-faults, weak beddings). When hydraulic fractures interact with natural fractures, they will either be arrested or transect the natural fractures depend on the leak-off characteristic of the natural fractures. The effective leak-off characteristic in a naturally fractured reservoir is an essential input for hydraulic fracturing simulation and consequent completion design as well as reservoir simulation (e.g., dual porosity and dual permeability) and consequent production optimization.\u0000 A novel method of estimating the effective leak-off characteristic in a naturally fractured reservoir is developed directly from hydraulic fracturing diagnostic tests such as minifrac and DFIT utilizing eXtended Finite Element Method (XFEM)-based 3D hydraulic fracturing model. Complex behaviors of hydraulic fractures interacting with natural fractures are simulated in the XFEM-based hydraulic fracturing model and history-matched with minifrac/DFIT data (i.e., treating pressure), in order to estimate effective leak-off characteristics of naturally fractured reservoirs.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125541498","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}
S. Nejadi, Julian D. Ortiz, Javier Sánchez, Xiaomeng Yang, Hosein Kalaei, S. Abbas
Producing bitumen using SAGD requires a significant amount of water and energy, resulting in a large amount of greenhouse gas emissions. Therefore, reducing the steam-oil ratio (SOR) in SAGD is critical to make the oil recovery process profitable and sustainable in a carbon-constrained world. This paper presents the potential benefits of co-injecting water-soluble volatile additives with steam in SAGD. The objective of the process is to decrease the SOR while maintaining SAGD-like oil production rates at economical chemical additives concentrations. Through a comprehensive experimental study, multiphase behaviour of the additive-water-bitumen system, mixture's viscosity, additive thermal stability, adsorption, emulsion stability, and recovery performance were evaluated. Extensive coreflooding experimental tests quantified the potential for improved oil recovery and SOR reduction. The experimental variables included additive concentration, water-oil ratio, and temperature. The studies showed that the additives improved oil recovery by promoting the formation of oil-in-water emulsions at the producing SOR. A series of reservoir simulation studies were also conducted for a field pilot design and evaluation of key performance indicators. Two different methodologies, equilibrium and non-equilibrium, were used to model the steam additive behaviour under both transient and steady-state conditions. Data obtained from coreflooding and viscosity measurements were the primary inputs of the reservoir simulation models. The fine-tuned reservoir simulation model quantified the technology uncertainties using multiple equally probable realizations of the reservoir to design and optimize the field pilot's injection scenarios and operating conditions. The simulation results showed SOR reduction of up to 25% with steam additives co-injection for the designed concentrations. Different phenomena such as additive transportation, condensation, additive degradation, and adsorption in a growing steam chamber were included in the numerical model. Based on the experimental and reservoir simulation results, a 4-well pair field pilot was designed, built, and put in operation at the Surmont SAGD project.
{"title":"Steam Additives to Reduce the Steam-Oil Ratio in SAGD: Experimental Analysis, Pilot Design, and Field Application","authors":"S. Nejadi, Julian D. Ortiz, Javier Sánchez, Xiaomeng Yang, Hosein Kalaei, S. Abbas","doi":"10.2118/208879-ms","DOIUrl":"https://doi.org/10.2118/208879-ms","url":null,"abstract":"\u0000 Producing bitumen using SAGD requires a significant amount of water and energy, resulting in a large amount of greenhouse gas emissions. Therefore, reducing the steam-oil ratio (SOR) in SAGD is critical to make the oil recovery process profitable and sustainable in a carbon-constrained world.\u0000 This paper presents the potential benefits of co-injecting water-soluble volatile additives with steam in SAGD. The objective of the process is to decrease the SOR while maintaining SAGD-like oil production rates at economical chemical additives concentrations.\u0000 Through a comprehensive experimental study, multiphase behaviour of the additive-water-bitumen system, mixture's viscosity, additive thermal stability, adsorption, emulsion stability, and recovery performance were evaluated. Extensive coreflooding experimental tests quantified the potential for improved oil recovery and SOR reduction. The experimental variables included additive concentration, water-oil ratio, and temperature. The studies showed that the additives improved oil recovery by promoting the formation of oil-in-water emulsions at the producing SOR.\u0000 A series of reservoir simulation studies were also conducted for a field pilot design and evaluation of key performance indicators. Two different methodologies, equilibrium and non-equilibrium, were used to model the steam additive behaviour under both transient and steady-state conditions. Data obtained from coreflooding and viscosity measurements were the primary inputs of the reservoir simulation models. The fine-tuned reservoir simulation model quantified the technology uncertainties using multiple equally probable realizations of the reservoir to design and optimize the field pilot's injection scenarios and operating conditions.\u0000 The simulation results showed SOR reduction of up to 25% with steam additives co-injection for the designed concentrations. Different phenomena such as additive transportation, condensation, additive degradation, and adsorption in a growing steam chamber were included in the numerical model. Based on the experimental and reservoir simulation results, a 4-well pair field pilot was designed, built, and put in operation at the Surmont SAGD project.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114639632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Oil displacement tests were carried out in a 45-cm long sand-pack at temperatures ranging from 64 to 217 °C using a viscous oil (PAO-100), deionized water and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to assess the effect of temperature on gas/oil relative permeability in viscous oil systems. We employed a new systematic algorithm to successfully implement a history matching scheme to infer the two-phase gas/heavy oil relative permeabilities from the core-flood data. We noted that at the end of the gas flooding, the "final" residual oil saturation still eluded us even after tens of pore volumes of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. A history-matching technique was used to determine the uncertain parameters of the oil/gas relative permeability curves, including the two exponents of the extended Corey equation (N° and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted. The remaining four parameters (i.e., Corey exponents, true residual oil saturation and gas endpoint relative permeability) were obtained from history matched simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.
{"title":"Effect of Temperature on Gas/Oil Relative Permeability in Viscous Oil Reservoirs","authors":"Saket Kumar, H. Sarma, B. Maini","doi":"10.2118/208897-ms","DOIUrl":"https://doi.org/10.2118/208897-ms","url":null,"abstract":"\u0000 Oil displacement tests were carried out in a 45-cm long sand-pack at temperatures ranging from 64 to 217 °C using a viscous oil (PAO-100), deionized water and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to assess the effect of temperature on gas/oil relative permeability in viscous oil systems.\u0000 We employed a new systematic algorithm to successfully implement a history matching scheme to infer the two-phase gas/heavy oil relative permeabilities from the core-flood data. We noted that at the end of the gas flooding, the \"final\" residual oil saturation still eluded us even after tens of pore volumes of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable.\u0000 A history-matching technique was used to determine the uncertain parameters of the oil/gas relative permeability curves, including the two exponents of the extended Corey equation (N° and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted. The remaining four parameters (i.e., Corey exponents, true residual oil saturation and gas endpoint relative permeability) were obtained from history matched simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126079079","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 hybrid steam-solvent injection has been considered as a promising technique for enhancing heavy oil/bitumen recovery, while its main mechanisms including the heat transferred and dissolution of solvents (e.g., C3H8, C4H10, CO2, N2, and DME) into heavy oil/bitumen to reduce its viscosity and swell it are closely related to the phase behaviour of the solvents/water/heavy oil systems. To allow the seamless integration with the existing reservoir simulators, the traditional cubic equations of state (i.e., SRK EOS and PR EOS) have been modified and improved to accurately quantify the phase behaviour and physical properties of the aforementioned systems under equilibrium and nonequilibrium conditions. Firstly, a huge database has been built to develop the corresponding alpha functions by minimizing the deviation between the measured and calculated vapour pressures for water as well as nonhydrocarbon and hydrocarbon compounds available from the public domain. Such obtained alpha functions are further validated with enthalpy of vaporization for pure substances, and then the reduced temperature has been optimized and the eccentric factor has been redefined. Finally, a pressure-implicit strategy has been developed to optimize the binary interaction parameters (BIPs) by treating heavy oil as one pseudocomponent (PC) or multiple PCs. Also, the contributions of each solvent to the aforementioned systems have been compared and analyzed within a consistent and unified framework. In addition to new alpha functions for hydrocarbons and water, respectively, the reduced temperature is found to have its optimum value of 0.59 for the two equations of state (EOSs), while 0.60 is recommended for practical use. Such improved EOSs have been further employed to reproduce the experimentally measured multiphase boundaries (or pseudo-bubble-point pressures), density, viscosity, (mutual) solubility, and preferential mass transfer for the aforementioned mixtures under equilibrium and nonequilibrium conditions. The swelling effect for the heavy oil can be enhanced due to the addition of C3H8 and/or C4H10 or their mixtures into the CO2 stream. Due to the existence of water, isenthalpic flash leads to more accurate quantification of multiphase boundaries and physical properties for the hybrid solvent-thermal processes. Each component of a binary or ternary gas mixture is found to diffuse preferentially into heavy oil at high pressures and elevated temperatures in the absence and presence of porous media, while each of them is found to exsolve differently from gas-saturated heavy oil under nonequilibrium conditions.
{"title":"Quantification of Phase Behaviour and Physical Properties of Alkane Solvents/CO2/ Water/Heavy Oil Systems under Equilibrium and Nonequilibrium Conditions","authors":"Daoyong Yang, Yunlong Li, Desheng Huang","doi":"10.2118/208968-ms","DOIUrl":"https://doi.org/10.2118/208968-ms","url":null,"abstract":"\u0000 The hybrid steam-solvent injection has been considered as a promising technique for enhancing heavy oil/bitumen recovery, while its main mechanisms including the heat transferred and dissolution of solvents (e.g., C3H8, C4H10, CO2, N2, and DME) into heavy oil/bitumen to reduce its viscosity and swell it are closely related to the phase behaviour of the solvents/water/heavy oil systems. To allow the seamless integration with the existing reservoir simulators, the traditional cubic equations of state (i.e., SRK EOS and PR EOS) have been modified and improved to accurately quantify the phase behaviour and physical properties of the aforementioned systems under equilibrium and nonequilibrium conditions. Firstly, a huge database has been built to develop the corresponding alpha functions by minimizing the deviation between the measured and calculated vapour pressures for water as well as nonhydrocarbon and hydrocarbon compounds available from the public domain. Such obtained alpha functions are further validated with enthalpy of vaporization for pure substances, and then the reduced temperature has been optimized and the eccentric factor has been redefined. Finally, a pressure-implicit strategy has been developed to optimize the binary interaction parameters (BIPs) by treating heavy oil as one pseudocomponent (PC) or multiple PCs. Also, the contributions of each solvent to the aforementioned systems have been compared and analyzed within a consistent and unified framework. In addition to new alpha functions for hydrocarbons and water, respectively, the reduced temperature is found to have its optimum value of 0.59 for the two equations of state (EOSs), while 0.60 is recommended for practical use. Such improved EOSs have been further employed to reproduce the experimentally measured multiphase boundaries (or pseudo-bubble-point pressures), density, viscosity, (mutual) solubility, and preferential mass transfer for the aforementioned mixtures under equilibrium and nonequilibrium conditions. The swelling effect for the heavy oil can be enhanced due to the addition of C3H8 and/or C4H10 or their mixtures into the CO2 stream. Due to the existence of water, isenthalpic flash leads to more accurate quantification of multiphase boundaries and physical properties for the hybrid solvent-thermal processes. Each component of a binary or ternary gas mixture is found to diffuse preferentially into heavy oil at high pressures and elevated temperatures in the absence and presence of porous media, while each of them is found to exsolve differently from gas-saturated heavy oil under nonequilibrium conditions.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115489095","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}
J. Rivero, Christopher Istchenko, C. Nascimento, Jianguang Cao, Hossein Aghabarati, Michael Bergen
In this paper, we propose a methodology to iteratively couple a wellbore simulator and a reservoir simulator in order to model the complex flow regimes that exist in a producing SAGD well while still taking into consideration the fluid movement and distribution within the reservoir. The process was successfully tested and implemented in two SAGD pads and the results were compared with those obtained using a commercial, fully-coupled reservoir-wellbore model. This method addresses the modeling limitations encountered in typical thermal reservoir simulators that use source/sink or discretized formulations to describe wellbore flow. SAGD producers exhibit overly complex flow regimes caused by the presence of a steam phase that can condense within the wellbore and promote significant variations in temperatures and pressures along the tubulars. Therefore, standalone wellbore simulators are necessary to predict performance as accurately as possible; however, using a wellbore simulator alone will neglect the effects caused by varying inflow conditions from the reservoir. With these variations occurring both in time and in space (along the wellbore), it is necessary to include the dynamic input of a reservoir simulator, hence the rationale for coupling both models. The algorithm devised to integrate the wellbore and reservoir simulators was coded into a standalone GUI-driven computer program called a coupler. The coupler was used to evaluate the performance of new SAGD pairs and new infill producers featuring flow devices and slanted trajectories. In this work, we will present the results of field case studies with the proposed coupling approach to evaluate the effect on ultimate recovery of drilling new SAGD pairs and SAGD infills using toe-up or toe-down trajectories as well as fitting these wells with inflow control devices. When applying the coupling workflow to the case studies, we determined that despite challenging conditions, it is possible to have inclined SAGD wells properly transition from preheating to production as well as allowing access to previously untapped parts of the reservoir resources, which increased ultimate recovery.
{"title":"Coupling a Thermal Reservoir Simulator with a Dynamic, Multiphase Wellbore Flow Simulator to Rigorously Model Complex SAGD Well Geometries and Completions","authors":"J. Rivero, Christopher Istchenko, C. Nascimento, Jianguang Cao, Hossein Aghabarati, Michael Bergen","doi":"10.2118/208918-ms","DOIUrl":"https://doi.org/10.2118/208918-ms","url":null,"abstract":"\u0000 In this paper, we propose a methodology to iteratively couple a wellbore simulator and a reservoir simulator in order to model the complex flow regimes that exist in a producing SAGD well while still taking into consideration the fluid movement and distribution within the reservoir. The process was successfully tested and implemented in two SAGD pads and the results were compared with those obtained using a commercial, fully-coupled reservoir-wellbore model. This method addresses the modeling limitations encountered in typical thermal reservoir simulators that use source/sink or discretized formulations to describe wellbore flow.\u0000 SAGD producers exhibit overly complex flow regimes caused by the presence of a steam phase that can condense within the wellbore and promote significant variations in temperatures and pressures along the tubulars. Therefore, standalone wellbore simulators are necessary to predict performance as accurately as possible; however, using a wellbore simulator alone will neglect the effects caused by varying inflow conditions from the reservoir. With these variations occurring both in time and in space (along the wellbore), it is necessary to include the dynamic input of a reservoir simulator, hence the rationale for coupling both models.\u0000 The algorithm devised to integrate the wellbore and reservoir simulators was coded into a standalone GUI-driven computer program called a coupler. The coupler was used to evaluate the performance of new SAGD pairs and new infill producers featuring flow devices and slanted trajectories.\u0000 In this work, we will present the results of field case studies with the proposed coupling approach to evaluate the effect on ultimate recovery of drilling new SAGD pairs and SAGD infills using toe-up or toe-down trajectories as well as fitting these wells with inflow control devices. When applying the coupling workflow to the case studies, we determined that despite challenging conditions, it is possible to have inclined SAGD wells properly transition from preheating to production as well as allowing access to previously untapped parts of the reservoir resources, which increased ultimate recovery.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130730810","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper provides a workflow to automate the application of multi-segment Arps decline model to forecast production in unconventional reservoirs. Due to significant activity in the shale plays, a single reservoir engineer may be tasked with managing hundreds of wells. In such cases, production forecasting using a multi-segment Arps model for all individual wells can be a challenging and time-consuming process. Although popular industry software provide some relief, each approach has its individual limitations. We present a workflow to automate the application of multi-segmented Arps decline model for easier and more accurate production forecasting using suitable statistical and machine learning methods. We start by removing outliers from our rate normalized pressure (RNP) data using angle-based outlier detection (ABOD) technique. This technique helps us clean our production data objectively to improve production forecasting and rate transient analysis (RTA). Next, we correct the non-monotonic behavior of material balance time (MBT) and smooth the RNP data using a constrained generalized additive model. We follow it by using the Ramer–Douglas–Peucker (RDP) algorithm as a change-point detection technique to automate the flow regime identification process. Finally, we calculate a b-value for each identified flow regime and forecast future production. We demonstrate the complete workflow using a field example from shale play. The presented workflow effectively and efficiently automates the rate transient analysis work and production forecasting using multi-segment Arps decline model. This results in more accurate production forecasts and greatly enhanced work productivity. The workflow presented, based on selected algorithms from statistics and machine-learning, automates multi-segment Arp’s decline curve analysis, and it can be used to forecast production for a large number of unconventional wells in a simple and time efficient manner.
{"title":"Statistical and Machine-Learning Methods Automate Multi-Segment Arps Decline Model Workflow to Forecast Production in Unconventional Reservoirs","authors":"H. S. Jha, A. Khanal, John W. Lee","doi":"10.2118/208884-ms","DOIUrl":"https://doi.org/10.2118/208884-ms","url":null,"abstract":"\u0000 This paper provides a workflow to automate the application of multi-segment Arps decline model to forecast production in unconventional reservoirs. Due to significant activity in the shale plays, a single reservoir engineer may be tasked with managing hundreds of wells. In such cases, production forecasting using a multi-segment Arps model for all individual wells can be a challenging and time-consuming process. Although popular industry software provide some relief, each approach has its individual limitations. We present a workflow to automate the application of multi-segmented Arps decline model for easier and more accurate production forecasting using suitable statistical and machine learning methods.\u0000 We start by removing outliers from our rate normalized pressure (RNP) data using angle-based outlier detection (ABOD) technique. This technique helps us clean our production data objectively to improve production forecasting and rate transient analysis (RTA). Next, we correct the non-monotonic behavior of material balance time (MBT) and smooth the RNP data using a constrained generalized additive model. We follow it by using the Ramer–Douglas–Peucker (RDP) algorithm as a change-point detection technique to automate the flow regime identification process. Finally, we calculate a b-value for each identified flow regime and forecast future production. We demonstrate the complete workflow using a field example from shale play.\u0000 The presented workflow effectively and efficiently automates the rate transient analysis work and production forecasting using multi-segment Arps decline model. This results in more accurate production forecasts and greatly enhanced work productivity.\u0000 The workflow presented, based on selected algorithms from statistics and machine-learning, automates multi-segment Arp’s decline curve analysis, and it can be used to forecast production for a large number of unconventional wells in a simple and time efficient manner.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132350800","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}
As natural gas demand increases through the energy transition, due to shifts away from coal-fired power generation and increased hydrogen utilization, production and processing of high CO2 natural gas sources, such as the Horn River Basin in Northern British Columbia will become more economic and important. The capture process should be energy efficient and provide the lowest GHG intensity possible to ensure the maximum decarbonization benefit. The propylene carbonate-based Fluor SolventSM process provides CO2 capture from natural gas sources at up to 97% lower GHG intensity when compared to the use of a formulated MDEA solvent which was used at the largest plant constructed to date in this field.
{"title":"Fluor Solvent Offers Significantly Lower GHG Intensity CO2 Removal from Natural Gas Than MDEA for Horn River","authors":"Morgan Rodwell","doi":"10.2118/208912-ms","DOIUrl":"https://doi.org/10.2118/208912-ms","url":null,"abstract":"\u0000 As natural gas demand increases through the energy transition, due to shifts away from coal-fired power generation and increased hydrogen utilization, production and processing of high CO2 natural gas sources, such as the Horn River Basin in Northern British Columbia will become more economic and important. The capture process should be energy efficient and provide the lowest GHG intensity possible to ensure the maximum decarbonization benefit. The propylene carbonate-based Fluor SolventSM process provides CO2 capture from natural gas sources at up to 97% lower GHG intensity when compared to the use of a formulated MDEA solvent which was used at the largest plant constructed to date in this field.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133852004","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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