The traditional trial and error approach of history matching to obtain an accurate model requires engineers to control each uncertain parameter and can be quite time consuming and inefficient. However, automatic history matching (AHM), assisted by computers, is an efficient process to control a large number of parameters simultaneously by an algorithm that integrates a static model with dynamic data to minimize a misfit for improving reliability. It helps to reduce simulation run time as well. Particle Swarm Optimization (PSO) is a population based stochastic algorithm that can explore parameter space combined with the least squares single objective function. The process of AHM can adopt parameterization and realization methods to reduce inverse problems. In this study, realizations of various reservoir properties such as porosity, net to gross, relative permeability, horizontal and vertical permeability, and aquifer size were chosen for controlling throughout the AHM. History matching was conducted to validate the efficiency of each method. The guidelines for optimized AHM with a stochastic algorithm are also disccussed. The realization and parameterization methods improved matching results in a full-field application with resulting in a reduced misfit and in less. A stochastic algorithm generates multiple models to deduce control parameters to reduce a misfit. In this study we identified that PSO converged effectively with updated control parameters. The optimized AHM improved the accuracy of a full-field model although some misfit remained in the match to bottomhole pressure. We found that updating with too many parameters makes the problem difficult to solve while using too few leads to false convergence. In addition, while the simulation run time is critical, a full-field simulation model with reduced computational overhead is benefitial. In this study, we observed that the PSO was an efficient algorithm to update control parameters to reduce a misfit. Using the parameterization and realization as an assisted method helped find better results. Overall this study can be used as a guideline to optimize the process of history matching.
{"title":"Field Application Study on Automatic History Matching Using Particle Swarm Optimization","authors":"Sanghyu Lee, K. Stephen","doi":"10.2118/196678-ms","DOIUrl":"https://doi.org/10.2118/196678-ms","url":null,"abstract":"\u0000 The traditional trial and error approach of history matching to obtain an accurate model requires engineers to control each uncertain parameter and can be quite time consuming and inefficient. However, automatic history matching (AHM), assisted by computers, is an efficient process to control a large number of parameters simultaneously by an algorithm that integrates a static model with dynamic data to minimize a misfit for improving reliability. It helps to reduce simulation run time as well.\u0000 Particle Swarm Optimization (PSO) is a population based stochastic algorithm that can explore parameter space combined with the least squares single objective function. The process of AHM can adopt parameterization and realization methods to reduce inverse problems. In this study, realizations of various reservoir properties such as porosity, net to gross, relative permeability, horizontal and vertical permeability, and aquifer size were chosen for controlling throughout the AHM. History matching was conducted to validate the efficiency of each method. The guidelines for optimized AHM with a stochastic algorithm are also disccussed.\u0000 The realization and parameterization methods improved matching results in a full-field application with resulting in a reduced misfit and in less. A stochastic algorithm generates multiple models to deduce control parameters to reduce a misfit. In this study we identified that PSO converged effectively with updated control parameters. The optimized AHM improved the accuracy of a full-field model although some misfit remained in the match to bottomhole pressure.\u0000 We found that updating with too many parameters makes the problem difficult to solve while using too few leads to false convergence. In addition, while the simulation run time is critical, a full-field simulation model with reduced computational overhead is benefitial.\u0000 In this study, we observed that the PSO was an efficient algorithm to update control parameters to reduce a misfit. Using the parameterization and realization as an assisted method helped find better results. Overall this study can be used as a guideline to optimize the process of history matching.","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127170947","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}
F. Ursini, R. Rossi, L. Castelnuovo, A. Perrone, Ayman Bendari, Marco Pollero
Recent advances in data acquisition systems have helped in monitoring wells performance and recording their production parameters like pressure, temperature and valve opening in real time with high frequency. A cost-effective technology to estimate well production rates is Virtual Metering, which integrates real time data and analytical models. This paper presents the methodology of an innovative virtual metering tool and the promising results obtained in real case applications on gas, gas condensate and oil fields. A Virtual Metering tool has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve simultaneously dynamic pressure and temperature gradients (VLP) along with the choke equation to find the optimal solution rates that match physical sensor readings. Moreover, the tool manages the communication between real time data and the models enabling a safe storage of the results. Models require a manual calibration at reference dates based on well separator tests or MPFM readings, in a way to match total field production. After calibration, the algorithm is able to run automatically in real-time. Three implementations are presented about gas, gas and condensate and oil fields, showing the benefits and limitations of virtual meter application. Virtual meter proved to be a valid technology with the potential of even replacing MPFM results, especially in dry gas fields. Where MPFM are installed on each wellhead, virtual meter worked as redundant system and allowed to detect precociously flow meters malfunctioning. The allocation workflow has been modified in order to replace MPFM estimations with virtual meter ones. For oil fields with variable production parameters, the tool has provided reliable independent rate estimation by combining VLP and choke calculator in a unique optimization tool. The real time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a Production Data Management System software. Additional features of the tool are the following: a real-time input for pressure and rate transient analysis and a workflow for real-time well drawdown estimation of gas wells, which makes use of automatic p/z reservoir model update to estimate reservoir pressure. Moreover, this tool had a significant impact on production monitoring, improved the effectiveness of production optimization actions and the quality of history match of reservoir 3D model. This paper contains a novel approach of a reliable and robust virtual metering tool that can be flexibly applied to gas and oil fields through a unique optimization algorithm, which is able to combine information coming from production network and from the reservoir side. It gives benefit to company workflows by feeding external reservoir analysis applications that would not be possible without virtual meter results and uses the results of external applications for validation purpose.
{"title":"The Benefits of Virtual Meter Applications on Production Monitoring and Reservoir Management","authors":"F. Ursini, R. Rossi, L. Castelnuovo, A. Perrone, Ayman Bendari, Marco Pollero","doi":"10.2118/196654-ms","DOIUrl":"https://doi.org/10.2118/196654-ms","url":null,"abstract":"\u0000 Recent advances in data acquisition systems have helped in monitoring wells performance and recording their production parameters like pressure, temperature and valve opening in real time with high frequency. A cost-effective technology to estimate well production rates is Virtual Metering, which integrates real time data and analytical models. This paper presents the methodology of an innovative virtual metering tool and the promising results obtained in real case applications on gas, gas condensate and oil fields.\u0000 A Virtual Metering tool has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve simultaneously dynamic pressure and temperature gradients (VLP) along with the choke equation to find the optimal solution rates that match physical sensor readings. Moreover, the tool manages the communication between real time data and the models enabling a safe storage of the results. Models require a manual calibration at reference dates based on well separator tests or MPFM readings, in a way to match total field production. After calibration, the algorithm is able to run automatically in real-time.\u0000 Three implementations are presented about gas, gas and condensate and oil fields, showing the benefits and limitations of virtual meter application. Virtual meter proved to be a valid technology with the potential of even replacing MPFM results, especially in dry gas fields. Where MPFM are installed on each wellhead, virtual meter worked as redundant system and allowed to detect precociously flow meters malfunctioning. The allocation workflow has been modified in order to replace MPFM estimations with virtual meter ones. For oil fields with variable production parameters, the tool has provided reliable independent rate estimation by combining VLP and choke calculator in a unique optimization tool. The real time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a Production Data Management System software. Additional features of the tool are the following: a real-time input for pressure and rate transient analysis and a workflow for real-time well drawdown estimation of gas wells, which makes use of automatic p/z reservoir model update to estimate reservoir pressure. Moreover, this tool had a significant impact on production monitoring, improved the effectiveness of production optimization actions and the quality of history match of reservoir 3D model.\u0000 This paper contains a novel approach of a reliable and robust virtual metering tool that can be flexibly applied to gas and oil fields through a unique optimization algorithm, which is able to combine information coming from production network and from the reservoir side. It gives benefit to company workflows by feeding external reservoir analysis applications that would not be possible without virtual meter results and uses the results of external applications for validation purpose.","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128946149","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}
M. Dernaika, S. Masalmeh, Bashar Mansour, Osama Al Jallad, S. Koronfol
In carbonate reservoirs, permeability prediction is often difficult due to the influence of various geological variables that control fluid flow. Many attempts have been made to calculate permeability from porosity by using theoretical and empirical equations. The suggested permeability models have been questionable in carbonates due to inherent heterogeneity and complex pore systems. The main objective of this paper is to resolve the porosity-permeability relationships and evaluate existing models for predicting permeability in different carbonate rock types. Over 1000 core plugs were studied from 7 different carbonate reservoirs across the Middle East region; mainly cretaceous reservoirs. The plugs were carefully selected to represent main property variations in the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs and high-pressure mercury injection. Plug-scale X-ray CT imaging was acquired to ensure the samples were free of induced fractures and other anomalies that can affect the permeability measurement. Rock textures were analyzed in the thin-section photomicrographs and were classified based on their content as grainy, muddy and mixed. Special attention was given to the diagenesis effects mainly compaction, cementation and dissolution. The texture information was plotted in the porosity-permeability domain, and was found to produce three distinct porosity-permeability relationships. Each texture gave unique poro-perm trend, where the extent of the trend was controlled by diagenesis. Rock types were defined on each trend by detailed texture analysis and capillary pressure. Three different permeability equations (Kozney, Winland, Lucia) were evaluated to study their effectiveness in complex carbonate reservoirs. A new permeability equation was proposed to enhance the prediction results of the experimental data. Rock types were successfully classified based on porosity, permeability, capillarity and textural facies. Conclusive porosity-permeability relationships were obtained from textural rock properties and diagenesis, which were linked to rock types using capillary pressure. The texture-diagenesis based rock types provided more insight into the effects of geology on fluid flow and saturation. Available models may not fully describe permeability in heterogeneous rocks but they can improve our understanding of fluid flow characteristics and predict permeability in un-cored wells.
{"title":"Geology-Based Porosity-Permeability Correlations in Carbonate Rock Types","authors":"M. Dernaika, S. Masalmeh, Bashar Mansour, Osama Al Jallad, S. Koronfol","doi":"10.2118/196665-ms","DOIUrl":"https://doi.org/10.2118/196665-ms","url":null,"abstract":"\u0000 In carbonate reservoirs, permeability prediction is often difficult due to the influence of various geological variables that control fluid flow. Many attempts have been made to calculate permeability from porosity by using theoretical and empirical equations. The suggested permeability models have been questionable in carbonates due to inherent heterogeneity and complex pore systems. The main objective of this paper is to resolve the porosity-permeability relationships and evaluate existing models for predicting permeability in different carbonate rock types.\u0000 Over 1000 core plugs were studied from 7 different carbonate reservoirs across the Middle East region; mainly cretaceous reservoirs. The plugs were carefully selected to represent main property variations in the cored intervals. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs and high-pressure mercury injection. Plug-scale X-ray CT imaging was acquired to ensure the samples were free of induced fractures and other anomalies that can affect the permeability measurement. Rock textures were analyzed in the thin-section photomicrographs and were classified based on their content as grainy, muddy and mixed. Special attention was given to the diagenesis effects mainly compaction, cementation and dissolution.\u0000 The texture information was plotted in the porosity-permeability domain, and was found to produce three distinct porosity-permeability relationships. Each texture gave unique poro-perm trend, where the extent of the trend was controlled by diagenesis. Rock types were defined on each trend by detailed texture analysis and capillary pressure. Three different permeability equations (Kozney, Winland, Lucia) were evaluated to study their effectiveness in complex carbonate reservoirs. A new permeability equation was proposed to enhance the prediction results of the experimental data.\u0000 Rock types were successfully classified based on porosity, permeability, capillarity and textural facies. Conclusive porosity-permeability relationships were obtained from textural rock properties and diagenesis, which were linked to rock types using capillary pressure. The texture-diagenesis based rock types provided more insight into the effects of geology on fluid flow and saturation. Available models may not fully describe permeability in heterogeneous rocks but they can improve our understanding of fluid flow characteristics and predict permeability in un-cored wells.","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132772354","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}
Brandon Thibodeaux, T. Ramsay, F. Segovia, L. Hernandez, M. Ibrahim
A flow simulation-driven time-lapse seismic feasibility study is performed for the Amberjack field that leverages existing multi-vintage 4D time-lapse seismic data. The focus is a field consisting of stacked shelf and deepwater reservoir sands situated in the Gulf of Mexico in Mississippi Canyon Block 109 in 1,030 ft of water. The solution leverages seismic interpretation, seismic inversion, earth modeling, and reservoir simulation [including embedded petro-elastic modeling (PEM) capabilities] to enable the reconciliation of data across multiple seismic vintages and forecast the optimal future seismic survey acquisition in a closed-loop. The overarching feasibility solution is integrated and simulation-driven involving multi-vintage seismic inversion, spatially constraining the petrophysical property model by seismic inversion, and performing reservoir simulation with the embedded PEM. The PEM is used to compute P-impedance and Vp/Vs dynamically, which enables tuning to both historical production and multi-vintage seismic data. The process considers a hybrid fine-scale 3D geocellular model in which the only upscaling of petrophysical properties occurs when the P-impedance from seismic inversion is blocked to the 3D geocellular grid. This process minimizes resampling errors and promotes direct tuning of the simulator response with registered seismic that has been blocked to a geocellular earth model grid. The results illustrate a three-part simulation-to-seismic calibration procedure that culminates with a prediction step which leads to a simulation-proposed time-lapse seismic acquisition timeline that is consistent with the calibrated reservoir simulation model. The first calibration tunes the model to historical production profiles. The second calibration reconciles the dynamic P-impedance estimate of the simulated shallow reservoir with that of the seismic inversion blocked to the 3D geocellular grid. The combination of these two steps outline a seismic-driven history matching process whereby the simulation model is not only consistent with production data but also the subsurface geologic and fluid saturation description. Large and short wavelength disparities in the P-impedance calibration existing between the simulator response and the time-lapse seismic data are attributed to resampling errors as a result of seismic inversion-derived P-impedance being blocked to the 3D geocelluar grid, as well as sparse well control in the earth model which leads to the obscuring of some asset-specific characteristics. The results of the third calibration step show how the time-lapse seismic feasibility solution accurately confirms prior seismic surveys undertaken in the asset. Given this confirmation, the solution achieves a suitable prediction of seismic-derived rock property response from the reservoir simulator as well as the optimal future time-lapse seismic acquisition time.
{"title":"Closed-Loop Integrated Time-Lapse Seismic Feasibility in Amberjack Field – Deepwater Offshore Gulf of Mexico","authors":"Brandon Thibodeaux, T. Ramsay, F. Segovia, L. Hernandez, M. Ibrahim","doi":"10.2118/196670-ms","DOIUrl":"https://doi.org/10.2118/196670-ms","url":null,"abstract":"\u0000 A flow simulation-driven time-lapse seismic feasibility study is performed for the Amberjack field that leverages existing multi-vintage 4D time-lapse seismic data. The focus is a field consisting of stacked shelf and deepwater reservoir sands situated in the Gulf of Mexico in Mississippi Canyon Block 109 in 1,030 ft of water. The solution leverages seismic interpretation, seismic inversion, earth modeling, and reservoir simulation [including embedded petro-elastic modeling (PEM) capabilities] to enable the reconciliation of data across multiple seismic vintages and forecast the optimal future seismic survey acquisition in a closed-loop. The overarching feasibility solution is integrated and simulation-driven involving multi-vintage seismic inversion, spatially constraining the petrophysical property model by seismic inversion, and performing reservoir simulation with the embedded PEM. The PEM is used to compute P-impedance and Vp/Vs dynamically, which enables tuning to both historical production and multi-vintage seismic data. The process considers a hybrid fine-scale 3D geocellular model in which the only upscaling of petrophysical properties occurs when the P-impedance from seismic inversion is blocked to the 3D geocellular grid. This process minimizes resampling errors and promotes direct tuning of the simulator response with registered seismic that has been blocked to a geocellular earth model grid. The results illustrate a three-part simulation-to-seismic calibration procedure that culminates with a prediction step which leads to a simulation-proposed time-lapse seismic acquisition timeline that is consistent with the calibrated reservoir simulation model. The first calibration tunes the model to historical production profiles. The second calibration reconciles the dynamic P-impedance estimate of the simulated shallow reservoir with that of the seismic inversion blocked to the 3D geocellular grid. The combination of these two steps outline a seismic-driven history matching process whereby the simulation model is not only consistent with production data but also the subsurface geologic and fluid saturation description. Large and short wavelength disparities in the P-impedance calibration existing between the simulator response and the time-lapse seismic data are attributed to resampling errors as a result of seismic inversion-derived P-impedance being blocked to the 3D geocelluar grid, as well as sparse well control in the earth model which leads to the obscuring of some asset-specific characteristics. The results of the third calibration step show how the time-lapse seismic feasibility solution accurately confirms prior seismic surveys undertaken in the asset. Given this confirmation, the solution achieves a suitable prediction of seismic-derived rock property response from the reservoir simulator as well as the optimal future time-lapse seismic acquisition time.","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131813722","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}
H. Yonebayashi, H. Iwama, Katsumo Takabayashi, Y. Miyagawa, Takumi Watanabe
CO2 injection is one of widely applied enhanced oil recovery (EOR) techniques, moreover, it is expected to contribute to the climate change from a viewpoint of storing CO2 in reservoir. However, CO2 is well known to accelerate precipitating asphaltenes which often deteriorate production. To understand in-situ asphaltene-depositions, unevenly distributed in composite carbonate core during a CO2 flood test under reservoir conditions, were investigated through numerical modelling study. Tertiary mode CO2 core flood tests were performed. A core holder was vertically placed in an oven to maintain reservoir temperature and to avoid vertical segregation. A composite core consisting of four Ø1.5" × L2.75" plug cores, which had similar porosity range but slightly varied air permeabilities, was retrieved from a core holder after the flooding test. The remaining hydrocarbon was extracted by Dean-stark method, and heptane insoluble materials were extracted from each plug core via IP-143 method to observe distribution of asphaltene deposits. The variation of asphaltene mass in plug cores was investigated to explain its mechanism thermodynamically. The core flood test was completed to achieve a certain additional oil recovery by 15 pore volume CO2 injection without any unfavorable differential pressure. The remaining asphaltene mass in each plug core revealed a trend in which more asphaltene collected from the inlet-side core. We assumed a scenario to explain the uneven asphaltene distribution by incorporating the vaporized-gas-drive and CO2 condensing mechanism. Namely, asphaltenes deposited immediately when pure CO2 contacted with oil. The contact between more pure CO2 and oil might be more frequently occurred in inlet-side core. To reproduce the scenario, a cubic-plus-association (CPA) model was generated to estimate asphaltene precipitating behavior as injected gas composition varied. In the first plug core, more pure CO2 gas was considered to contact with fresh reservoir oil compared with the downstream cores which might have less pure CO2 because of its condensation. The light-intermediate hydrocarbon gas vaporized by CO2 was also considered to emphasize the trend of more asphaltene deposits in upstream-side cores. The CPA model revealed consistent phenomenon supporting the scenario.
{"title":"Distribution Mechanism of Asphaltene Deposits in CO2 Flooding Path: Interpretation by Numerical Model Based on Experimental Observation","authors":"H. Yonebayashi, H. Iwama, Katsumo Takabayashi, Y. Miyagawa, Takumi Watanabe","doi":"10.2118/196658-ms","DOIUrl":"https://doi.org/10.2118/196658-ms","url":null,"abstract":"\u0000 CO2 injection is one of widely applied enhanced oil recovery (EOR) techniques, moreover, it is expected to contribute to the climate change from a viewpoint of storing CO2 in reservoir. However, CO2 is well known to accelerate precipitating asphaltenes which often deteriorate production. To understand in-situ asphaltene-depositions, unevenly distributed in composite carbonate core during a CO2 flood test under reservoir conditions, were investigated through numerical modelling study.\u0000 Tertiary mode CO2 core flood tests were performed. A core holder was vertically placed in an oven to maintain reservoir temperature and to avoid vertical segregation. A composite core consisting of four Ø1.5\" × L2.75\" plug cores, which had similar porosity range but slightly varied air permeabilities, was retrieved from a core holder after the flooding test. The remaining hydrocarbon was extracted by Dean-stark method, and heptane insoluble materials were extracted from each plug core via IP-143 method to observe distribution of asphaltene deposits. The variation of asphaltene mass in plug cores was investigated to explain its mechanism thermodynamically.\u0000 The core flood test was completed to achieve a certain additional oil recovery by 15 pore volume CO2 injection without any unfavorable differential pressure. The remaining asphaltene mass in each plug core revealed a trend in which more asphaltene collected from the inlet-side core. We assumed a scenario to explain the uneven asphaltene distribution by incorporating the vaporized-gas-drive and CO2 condensing mechanism. Namely, asphaltenes deposited immediately when pure CO2 contacted with oil. The contact between more pure CO2 and oil might be more frequently occurred in inlet-side core. To reproduce the scenario, a cubic-plus-association (CPA) model was generated to estimate asphaltene precipitating behavior as injected gas composition varied. In the first plug core, more pure CO2 gas was considered to contact with fresh reservoir oil compared with the downstream cores which might have less pure CO2 because of its condensation. The light-intermediate hydrocarbon gas vaporized by CO2 was also considered to emphasize the trend of more asphaltene deposits in upstream-side cores. The CPA model revealed consistent phenomenon supporting the scenario.","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134236784","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}
Osama A. Abdelhamid, Shu Zhang, M. Maučec, Brett Fischbuch
Effective management of Voidage Replacement Ratio (VRR) throughout the producing life of an oil reservoir is essential for achieving optimal oil recovery. VRR is quantitatively defined as injection/production fluid volume ratio at reservoir conditions. The primary goal in managing voidage replacement is to replenish the energy in a reservoir to a degree that the producing wells yield hydrocarbons at economical rates. The determination of VRR, however, becomes more complicated when reservoirs are significantly affected by fluid influxes. This paper presents a method developed to optimize VRR calculations using streamlines, traced from finite-difference reservoir simulation model outputs. Good reservoir management practice necessitates that conventional VRR should be maintained at or above unity. Maintaining appropriate injection performance is therefore an essential requirement for achieving optimal oil recovery in secondary recovery processes. This can be achieved through effective VRR surveillance, water breakthrough monitoring, and reservoir pressure maintenance. This paper presents a new technique and associated workflow for rigorous VRR determination that resolves a number of shortcomings inherent in conventional VRR analysis. This rigorous VRRR determination methodology was applied to an existing field with considerable operating history including multiple displacement and recovery processes: primary depletion, aquifer influx, gas re-injection, gravity water injection, and power water injection. This new methodology utilizes finite difference reservoir simulation models to generate streamlines from the pressure field and fluxes. Streamlines represent flow paths between injectors and producers. The streamline trajectories with associated time-of-flight values thus obtained take into account geologic complexity, external fluxes, well locations, phase behavior, and reservoir flow behavior. Rigorous VRR estimates are obtained by accounting for the influxes and well allocation factors (WAF), which represent a measure of connectivity between specific injector/producer pairs with associated fluxes. The fluxes and WAF values are calculated automatically from the history-matched reservoir simulation model during streamline tracing for associated time steps. Traditionally, the well VRR values are calculated via the formulation of well inflow performance relationship (IPR), which may result in suboptimal estimations by not accounting for external sources of energy, such as influx from neighboring zones. The presented approach allows for improved optimisation of waterflood injection efficiency, where the off-set oil production can be derived directly from reservoir material balance (MB) calculations and streamline-generated well allocation factors. In order to facilitate VRR calculations with dynamic simulation regions, we propose a workflow for streamline (SLN) based VRR calculations using the time-dependent flow-based SLN-conditioned drainage vol
{"title":"Optimisation of Voidage Replacement Calculation Using Reservoir Simulations and Streamline Tracing","authors":"Osama A. Abdelhamid, Shu Zhang, M. Maučec, Brett Fischbuch","doi":"10.2118/196692-ms","DOIUrl":"https://doi.org/10.2118/196692-ms","url":null,"abstract":"\u0000 Effective management of Voidage Replacement Ratio (VRR) throughout the producing life of an oil reservoir is essential for achieving optimal oil recovery. VRR is quantitatively defined as injection/production fluid volume ratio at reservoir conditions. The primary goal in managing voidage replacement is to replenish the energy in a reservoir to a degree that the producing wells yield hydrocarbons at economical rates. The determination of VRR, however, becomes more complicated when reservoirs are significantly affected by fluid influxes. This paper presents a method developed to optimize VRR calculations using streamlines, traced from finite-difference reservoir simulation model outputs.\u0000 Good reservoir management practice necessitates that conventional VRR should be maintained at or above unity. Maintaining appropriate injection performance is therefore an essential requirement for achieving optimal oil recovery in secondary recovery processes. This can be achieved through effective VRR surveillance, water breakthrough monitoring, and reservoir pressure maintenance.\u0000 This paper presents a new technique and associated workflow for rigorous VRR determination that resolves a number of shortcomings inherent in conventional VRR analysis. This rigorous VRRR determination methodology was applied to an existing field with considerable operating history including multiple displacement and recovery processes: primary depletion, aquifer influx, gas re-injection, gravity water injection, and power water injection. This new methodology utilizes finite difference reservoir simulation models to generate streamlines from the pressure field and fluxes. Streamlines represent flow paths between injectors and producers. The streamline trajectories with associated time-of-flight values thus obtained take into account geologic complexity, external fluxes, well locations, phase behavior, and reservoir flow behavior. Rigorous VRR estimates are obtained by accounting for the influxes and well allocation factors (WAF), which represent a measure of connectivity between specific injector/producer pairs with associated fluxes. The fluxes and WAF values are calculated automatically from the history-matched reservoir simulation model during streamline tracing for associated time steps.\u0000 Traditionally, the well VRR values are calculated via the formulation of well inflow performance relationship (IPR), which may result in suboptimal estimations by not accounting for external sources of energy, such as influx from neighboring zones. The presented approach allows for improved optimisation of waterflood injection efficiency, where the off-set oil production can be derived directly from reservoir material balance (MB) calculations and streamline-generated well allocation factors. In order to facilitate VRR calculations with dynamic simulation regions, we propose a workflow for streamline (SLN) based VRR calculations using the time-dependent flow-based SLN-conditioned drainage vol","PeriodicalId":354509,"journal":{"name":"Day 3 Thu, September 19, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124240130","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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