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Christopher R Clarkson - One of the best experts on this subject based on the ideXlab platform.

  • reservoir and fluid characterization of a tight gas condensate well in the montney formation using recombination of separator samples and black oil history matching
    Journal of Natural Gas Science and Engineering, 2018
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract Liquid-rich shale (LRS) reservoirs are economically attractive but operationally challenging particularly for cases where multi-phase flow occurs within the reservoir. Proper treatment of PVT and rock properties, as well as rock-fluid interaction, in these unconventional reservoirs is central to providing improved short- and long-term oil and gas production forecasts. In the presence of limited surface sampling, the available analytical models often do not provide satisfactory results due to the uncertainty in the initial in-situ fluid system. In such situations, and particularly when there are many unknown parameters, numerical models are ideally suited, using a history matching framework, to assist with reservoir and fluid characterization. In this paper, production data from a multi-fractured horizontal well completed in a tight gas condensate reservoir in the Montney Formation in western Alberta, Canada is presented and analyzed using black oil numerical simulation. An assisted history-matching routine (i.e. Differential Evolution (DE) algorithm) is used in combination with black oil numerical simulations to characterize reservoir fluids and estimate reservoir and hydraulic fracture properties. The applicability of black oil numerical simulation for accurate prediction of the fluid model and well performance using numerous compositional numerical simulations and various fluid systems is first verified. The in-situ fluid is assumed to be a mixture of recombined separator samples with unknown oil-gas recombination ratio. The effect of time of sampling on the produced well stream composition is considered. Our results show that recombined separator sample mixtures collected early on during production of wells subjected to limited drawdown can successfully represent reservoir fluid properties with the exception of saturation Pressure. In other words, the reservoir fluid PVT behavior can be predicted by recombination of an early initial separator fluid sample only by varying the saturation Pressure. Hence, the assisted history matching can be performed using black oil numerical simulations with a reduced number of unknowns for the fluid system. The well/reservoir properties and unknown reservoir fluid are characterized in terms of a 12-parameter system. The history-matched results using DE could satisfactorily reproduce the water and hydrocarbon surface flow rates, and Flowing Bottomhole Pressure curves. The quality of results are comparable to those obtained previously (Hamdi et al., 2015) using a fully-compositional numerical model. The new workflow using assisted history-matching combined with black oil simulation provides a practical yet accurate method for characterizing fluid, reservoir and fracture properties in unconventional gas condensate systems.

  • history matching and forecasting tight shale gas condensate wells using combined analytical semi analytical and empirical methods
    Journal of Natural Gas Science and Engineering, 2015
    Co-Authors: Christopher R Clarkson, Hamid Behmanesh, J D Williamskovacs, Farhad Qanbari, Heidari M Sureshjani
    Abstract:

    Abstract The primary focus of the majority of current, and foreseeable, natural gas drilling within North America is low-permeability liquid-rich gas and gas condensate reservoirs, where the liquid fraction is now a major source of revenue. Development of these liquid-rich resources is aided by the use of multi-fractured horizontal wells (MFHWs), and is at an early stage; further research is required to appropriately manage the resource for optimal hydrocarbon recovery. The appropriate forecasting methodologies to apply to these tight liquid-rich plays are a focus of current research. While numerical simulation is the most rigorous forecasting methodology, practitioners have turned to simple analytical and empirical methods because of their ease-of-use and requirement of less data. However, these analytical and empirical approaches have limitations that limit their applicability for unconventional resevoirs with complex reservoir, hydraulic fracture and fluid properties. In this study, the workflow of Clarkson (2013b) is applied to address the limitations of existing empirical and analytical methods for forecasting MFHWs producing from liquid-rich tight gas/shale. The workflow calls for constraint of analytical models by linking inputs to rate-transient analysis-derived reservoir and hydraulic fracture properties, and constraining empirical model forecasts to be consistent with analytical model forecasts. In order to address the range in reservoir/fracture properties observed in shales, a suite of analytical models is proposed. Similarly, a suite of empirical methods is used, and the models yielding the most accurate matches to the analytical models are selected for forecasting. Lastly, in order to bridge the gap between analytical and empirical methods, the semi-analytical method introduced by Clarkson and Qanbari (2015), which has as its basis the contacted gas-in-place calculations of Agarwal (2010), is also used for forecasting. An important contribution of this work is the demonstration of the applicability of the analytical and semi-analytical models used in this work for tight gas/shale gas condensate MFHWs exhibiting multi-phase flow in the reservoir. As demonstrated in this study using simulation cases, constant condensate gas ratios can occur for tight/shale gas condensate wells exhibiting transient linear flow and Flowing at near constant Flowing Bottomhole Pressure, even for relatively rich gas cases, rendering the single-phase forecasting methods useful for forecasting gas and condensate phases. The accuracy of these methods is tested using simulated cases, and practicality of the workflow demonstrated using an actual field example of a liquid-rich shale MFHW. This study will be of interest to those petroleum engineers who are faced with forecasting a large number of liquid-rich shale wells, and desire methods that can be simply applied to constrain forecasts and improve accuracy.

  • production data analysis of tight gas condensate reservoirs
    Journal of Natural Gas Science and Engineering, 2015
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract The current focus on liquids-rich shale (LRS) plays in North America underscores the need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is an important technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable. This paper discusses production data analysis of constant Flowing Bottomhole Pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient matrix linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudoPressure and pseudotime functions so that the solutions for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, x f √ k . Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if FBHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells. The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used for this purpose.

Hamid Behmanesh - One of the best experts on this subject based on the ideXlab platform.

  • reservoir and fluid characterization of a tight gas condensate well in the montney formation using recombination of separator samples and black oil history matching
    Journal of Natural Gas Science and Engineering, 2018
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract Liquid-rich shale (LRS) reservoirs are economically attractive but operationally challenging particularly for cases where multi-phase flow occurs within the reservoir. Proper treatment of PVT and rock properties, as well as rock-fluid interaction, in these unconventional reservoirs is central to providing improved short- and long-term oil and gas production forecasts. In the presence of limited surface sampling, the available analytical models often do not provide satisfactory results due to the uncertainty in the initial in-situ fluid system. In such situations, and particularly when there are many unknown parameters, numerical models are ideally suited, using a history matching framework, to assist with reservoir and fluid characterization. In this paper, production data from a multi-fractured horizontal well completed in a tight gas condensate reservoir in the Montney Formation in western Alberta, Canada is presented and analyzed using black oil numerical simulation. An assisted history-matching routine (i.e. Differential Evolution (DE) algorithm) is used in combination with black oil numerical simulations to characterize reservoir fluids and estimate reservoir and hydraulic fracture properties. The applicability of black oil numerical simulation for accurate prediction of the fluid model and well performance using numerous compositional numerical simulations and various fluid systems is first verified. The in-situ fluid is assumed to be a mixture of recombined separator samples with unknown oil-gas recombination ratio. The effect of time of sampling on the produced well stream composition is considered. Our results show that recombined separator sample mixtures collected early on during production of wells subjected to limited drawdown can successfully represent reservoir fluid properties with the exception of saturation Pressure. In other words, the reservoir fluid PVT behavior can be predicted by recombination of an early initial separator fluid sample only by varying the saturation Pressure. Hence, the assisted history matching can be performed using black oil numerical simulations with a reduced number of unknowns for the fluid system. The well/reservoir properties and unknown reservoir fluid are characterized in terms of a 12-parameter system. The history-matched results using DE could satisfactorily reproduce the water and hydrocarbon surface flow rates, and Flowing Bottomhole Pressure curves. The quality of results are comparable to those obtained previously (Hamdi et al., 2015) using a fully-compositional numerical model. The new workflow using assisted history-matching combined with black oil simulation provides a practical yet accurate method for characterizing fluid, reservoir and fracture properties in unconventional gas condensate systems.

  • history matching and forecasting tight shale gas condensate wells using combined analytical semi analytical and empirical methods
    Journal of Natural Gas Science and Engineering, 2015
    Co-Authors: Christopher R Clarkson, Hamid Behmanesh, J D Williamskovacs, Farhad Qanbari, Heidari M Sureshjani
    Abstract:

    Abstract The primary focus of the majority of current, and foreseeable, natural gas drilling within North America is low-permeability liquid-rich gas and gas condensate reservoirs, where the liquid fraction is now a major source of revenue. Development of these liquid-rich resources is aided by the use of multi-fractured horizontal wells (MFHWs), and is at an early stage; further research is required to appropriately manage the resource for optimal hydrocarbon recovery. The appropriate forecasting methodologies to apply to these tight liquid-rich plays are a focus of current research. While numerical simulation is the most rigorous forecasting methodology, practitioners have turned to simple analytical and empirical methods because of their ease-of-use and requirement of less data. However, these analytical and empirical approaches have limitations that limit their applicability for unconventional resevoirs with complex reservoir, hydraulic fracture and fluid properties. In this study, the workflow of Clarkson (2013b) is applied to address the limitations of existing empirical and analytical methods for forecasting MFHWs producing from liquid-rich tight gas/shale. The workflow calls for constraint of analytical models by linking inputs to rate-transient analysis-derived reservoir and hydraulic fracture properties, and constraining empirical model forecasts to be consistent with analytical model forecasts. In order to address the range in reservoir/fracture properties observed in shales, a suite of analytical models is proposed. Similarly, a suite of empirical methods is used, and the models yielding the most accurate matches to the analytical models are selected for forecasting. Lastly, in order to bridge the gap between analytical and empirical methods, the semi-analytical method introduced by Clarkson and Qanbari (2015), which has as its basis the contacted gas-in-place calculations of Agarwal (2010), is also used for forecasting. An important contribution of this work is the demonstration of the applicability of the analytical and semi-analytical models used in this work for tight gas/shale gas condensate MFHWs exhibiting multi-phase flow in the reservoir. As demonstrated in this study using simulation cases, constant condensate gas ratios can occur for tight/shale gas condensate wells exhibiting transient linear flow and Flowing at near constant Flowing Bottomhole Pressure, even for relatively rich gas cases, rendering the single-phase forecasting methods useful for forecasting gas and condensate phases. The accuracy of these methods is tested using simulated cases, and practicality of the workflow demonstrated using an actual field example of a liquid-rich shale MFHW. This study will be of interest to those petroleum engineers who are faced with forecasting a large number of liquid-rich shale wells, and desire methods that can be simply applied to constrain forecasts and improve accuracy.

  • production data analysis of tight gas condensate reservoirs
    Journal of Natural Gas Science and Engineering, 2015
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract The current focus on liquids-rich shale (LRS) plays in North America underscores the need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is an important technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable. This paper discusses production data analysis of constant Flowing Bottomhole Pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient matrix linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudoPressure and pseudotime functions so that the solutions for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, x f √ k . Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if FBHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells. The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used for this purpose.

Rivas, Jesús David - One of the best experts on this subject based on the ideXlab platform.

  • Desarrollo de un programa de computador para estimar la presión de fondo fluyendo por medio de mediciones del nivel dinámico de un pozo con levantamiento artificial bajo flujo multifásico
    'Universidad Surcolombiana', 2015
    Co-Authors: Sepúlveda Gaona, Jairo Antonio, Vargas, Moisés Jesús, Rivas, Jesús David
    Abstract:

    This paper presents the results obtained from the development of a program for calculating the Bottomhole Pressure. The program allows to simplify the measurements in the well and minimizes costs by avoiding stop production in order to obtain the required data. In the development of this work is used a method to calcúlate the Flowing Bottomhole Pressure, from fluid level measurements. Using models to characterize the multiphase flow in a well, experimental work and theoretical arguments, the calculation procedure allows to calcúlate the Flowing Bottomhole Pressure, without shutting the well. Also this method allows to take into account real geometry of the well. The validation of the results is based on experimental data found in the literature and real fleld data, the comparison allows us to make a proper evaluation of this model.En este artículo se presentan los resultados obtenidos a partir del desarrollo de un programa para el cálculo de la presión de fondo fluyendo. El programa permite simplificar las mediciones en el pozo y minimizar costos, evitando detener la producción con el fin de obtener los datos necesarios. En el desarrollo de este trabajo se implemento un procedimiento para calcular la presión de fondo fluyendo, a partir de mediciones del nivel de fluido. Con ayuda del uso de modelos para caracterizar el flujo multifásico en un pozo, trabajo experimental y argumentos teóricos, el procedimiento de cálculo permite predecir la presión de fondo fluyendo, sin necesidad de cerrar el pozo. Además este método permite tener en cuenta, la geometría real del pozo. La validación de los resultados se hace con base en datos de campo reales, cuya comparación nos permite hacer una evaluación acertada de este modelo

Sepúlveda Gaona, Jairo Antonio - One of the best experts on this subject based on the ideXlab platform.

  • Desarrollo de un programa de computador para estimar la presión de fondo fluyendo por medio de mediciones del nivel dinámico de un pozo con levantamiento artificial bajo flujo multifásico
    'Universidad Surcolombiana', 2015
    Co-Authors: Sepúlveda Gaona, Jairo Antonio, Vargas, Moisés Jesús, Rivas, Jesús David
    Abstract:

    This paper presents the results obtained from the development of a program for calculating the Bottomhole Pressure. The program allows to simplify the measurements in the well and minimizes costs by avoiding stop production in order to obtain the required data. In the development of this work is used a method to calcúlate the Flowing Bottomhole Pressure, from fluid level measurements. Using models to characterize the multiphase flow in a well, experimental work and theoretical arguments, the calculation procedure allows to calcúlate the Flowing Bottomhole Pressure, without shutting the well. Also this method allows to take into account real geometry of the well. The validation of the results is based on experimental data found in the literature and real fleld data, the comparison allows us to make a proper evaluation of this model.En este artículo se presentan los resultados obtenidos a partir del desarrollo de un programa para el cálculo de la presión de fondo fluyendo. El programa permite simplificar las mediciones en el pozo y minimizar costos, evitando detener la producción con el fin de obtener los datos necesarios. En el desarrollo de este trabajo se implemento un procedimiento para calcular la presión de fondo fluyendo, a partir de mediciones del nivel de fluido. Con ayuda del uso de modelos para caracterizar el flujo multifásico en un pozo, trabajo experimental y argumentos teóricos, el procedimiento de cálculo permite predecir la presión de fondo fluyendo, sin necesidad de cerrar el pozo. Además este método permite tener en cuenta, la geometría real del pozo. La validación de los resultados se hace con base en datos de campo reales, cuya comparación nos permite hacer una evaluación acertada de este modelo

Hamidreza Hamdi - One of the best experts on this subject based on the ideXlab platform.

  • reservoir and fluid characterization of a tight gas condensate well in the montney formation using recombination of separator samples and black oil history matching
    Journal of Natural Gas Science and Engineering, 2018
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract Liquid-rich shale (LRS) reservoirs are economically attractive but operationally challenging particularly for cases where multi-phase flow occurs within the reservoir. Proper treatment of PVT and rock properties, as well as rock-fluid interaction, in these unconventional reservoirs is central to providing improved short- and long-term oil and gas production forecasts. In the presence of limited surface sampling, the available analytical models often do not provide satisfactory results due to the uncertainty in the initial in-situ fluid system. In such situations, and particularly when there are many unknown parameters, numerical models are ideally suited, using a history matching framework, to assist with reservoir and fluid characterization. In this paper, production data from a multi-fractured horizontal well completed in a tight gas condensate reservoir in the Montney Formation in western Alberta, Canada is presented and analyzed using black oil numerical simulation. An assisted history-matching routine (i.e. Differential Evolution (DE) algorithm) is used in combination with black oil numerical simulations to characterize reservoir fluids and estimate reservoir and hydraulic fracture properties. The applicability of black oil numerical simulation for accurate prediction of the fluid model and well performance using numerous compositional numerical simulations and various fluid systems is first verified. The in-situ fluid is assumed to be a mixture of recombined separator samples with unknown oil-gas recombination ratio. The effect of time of sampling on the produced well stream composition is considered. Our results show that recombined separator sample mixtures collected early on during production of wells subjected to limited drawdown can successfully represent reservoir fluid properties with the exception of saturation Pressure. In other words, the reservoir fluid PVT behavior can be predicted by recombination of an early initial separator fluid sample only by varying the saturation Pressure. Hence, the assisted history matching can be performed using black oil numerical simulations with a reduced number of unknowns for the fluid system. The well/reservoir properties and unknown reservoir fluid are characterized in terms of a 12-parameter system. The history-matched results using DE could satisfactorily reproduce the water and hydrocarbon surface flow rates, and Flowing Bottomhole Pressure curves. The quality of results are comparable to those obtained previously (Hamdi et al., 2015) using a fully-compositional numerical model. The new workflow using assisted history-matching combined with black oil simulation provides a practical yet accurate method for characterizing fluid, reservoir and fracture properties in unconventional gas condensate systems.

  • production data analysis of tight gas condensate reservoirs
    Journal of Natural Gas Science and Engineering, 2015
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract The current focus on liquids-rich shale (LRS) plays in North America underscores the need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is an important technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable. This paper discusses production data analysis of constant Flowing Bottomhole Pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient matrix linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudoPressure and pseudotime functions so that the solutions for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, x f √ k . Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if FBHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells. The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used for this purpose.