Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.
{"title":"A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates","authors":"Brenda Azuara Diliegros, Roberto Aguilera","doi":"10.2118/208893-pa","DOIUrl":"https://doi.org/10.2118/208893-pa","url":null,"abstract":"Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"30 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135963610","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Hui, Bradley T. Mallison, Sunil G. Thomas, Pierre Muron, Matthieu Rousset, E. Earnest, T. Playton, H. Vo, C. Jensen
Natural fracture systems comprise numerous small features and relatively few large ones. At field scale, it is impractical to treat all fractures explicitly. We represent the largest fractures using an embedded discrete fracture model (EDFM) and account for smaller ones using a dual-porosity, dual-permeability (DPDK) idealized representation of the fracture network. The hybrid EDFM + DPDK approach uses consistent discretization schemes and efficiently simulates realistic field cases. Further speedup can be obtained using aggregation-based upscaling. Capabilities to visualize and post-process simulation results facilitate understanding for effective management of fractured reservoirs. The proposed approach embeds large discrete fractures as EDFM within a DPDK grid (which contains both matrix and idealized fracture continua for smaller fractures) and captures all connections among the triple media. In contrast with existing EDFM formulations, we account for discrete fracture spacing within each matrix cell via a new matrix-fracture transfer term and use consistent assumptions for classical EDFM and DPDK calculations. In addition, the workflow enables coarse EDFM representations using flow-based cell-aggregation upscaling for computational efficiency. Using a synthetic case, we show that the proposed EDFM + DPDK approach provides a close match of simulation results from a reference model that represents all fractures explicitly, while providing runtime speedup. It is also more accurate than previous standard EDFM and DPDK models. We demonstrate that the matrix-fracture transfer function agrees with flow-based upscaling of high-resolution fracture models. Next, the automated workflow is applied to a waterflooding study for a giant carbonate reservoir, with an ensemble of stochastic fracture realizations. The overall workflow provides the computational efficiency needed for performance forecasts in practical field studies, and the 3D visualization allows for the derivation of insights into recovery mechanisms. Finally, we apply a finite-volume tracer-based flux post-processing scheme on simulation results to analyze production allocation and sweep for understanding expected waterflood performance.
{"title":"A Hybrid Embedded Discrete Fracture Model and Dual-Porosity, Dual-Permeability Workflow for Hierarchical Treatment of Fractures in Practical Field Studies","authors":"M. Hui, Bradley T. Mallison, Sunil G. Thomas, Pierre Muron, Matthieu Rousset, E. Earnest, T. Playton, H. Vo, C. Jensen","doi":"10.2118/209293-pa","DOIUrl":"https://doi.org/10.2118/209293-pa","url":null,"abstract":"\u0000 Natural fracture systems comprise numerous small features and relatively few large ones. At field scale, it is impractical to treat all fractures explicitly. We represent the largest fractures using an embedded discrete fracture model (EDFM) and account for smaller ones using a dual-porosity, dual-permeability (DPDK) idealized representation of the fracture network. The hybrid EDFM + DPDK approach uses consistent discretization schemes and efficiently simulates realistic field cases. Further speedup can be obtained using aggregation-based upscaling. Capabilities to visualize and post-process simulation results facilitate understanding for effective management of fractured reservoirs. The proposed approach embeds large discrete fractures as EDFM within a DPDK grid (which contains both matrix and idealized fracture continua for smaller fractures) and captures all connections among the triple media. In contrast with existing EDFM formulations, we account for discrete fracture spacing within each matrix cell via a new matrix-fracture transfer term and use consistent assumptions for classical EDFM and DPDK calculations. In addition, the workflow enables coarse EDFM representations using flow-based cell-aggregation upscaling for computational efficiency. Using a synthetic case, we show that the proposed EDFM + DPDK approach provides a close match of simulation results from a reference model that represents all fractures explicitly, while providing runtime speedup. It is also more accurate than previous standard EDFM and DPDK models. We demonstrate that the matrix-fracture transfer function agrees with flow-based upscaling of high-resolution fracture models. Next, the automated workflow is applied to a waterflooding study for a giant carbonate reservoir, with an ensemble of stochastic fracture realizations. The overall workflow provides the computational efficiency needed for performance forecasts in practical field studies, and the 3D visualization allows for the derivation of insights into recovery mechanisms. Finally, we apply a finite-volume tracer-based flux post-processing scheme on simulation results to analyze production allocation and sweep for understanding expected waterflood performance.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"18 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86039709","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Zeinabady, C. R. Clarkson, S. Razzaghi, S. Haqparast, A. L. Benson, M. Azad
Summary The existence of faults, pre-existing hydraulic fractures, and depleted areas can negatively impact the development of unconventional reservoirs using multifractured horizontal wells (MFHWs). For example, the triggering of fault slippage through hydraulic fracturing can create the environmental hazard known as induced seismicity (earthquakes caused by hydraulic fracturing). A premium has therefore been placed on the development of technologies that can be used to identify the locations of fault systems (particularly if they are subseismic) as well as pre-existing hydraulic fractures and depleted areas. The objective of this study is to develop a diagnostic tool to identify these conditions using DFIT-FBA, a modified diagnostic fracture injection test (DFIT) with flowback analysis (FBA). The time and cost efficiencies of the DFIT-FBA method in reservoir characterization provides an opportunity to conduct multiple field tests at a single point or along the lateral section of a horizontal well. An analytical model that considers critical processes and mechanisms occurring during DFIT-FBA was first developed herein. The results of analytical modeling demonstrate that reservoir heterogeneities (i.e., faults) can be identified either by implementing multiple cycles of the DFIT-FBA method at a single point or by applying multiple DFIT-FBAs at different points along the lateral section of a horizontal well or at different wells. The analytical model is then verified using a fully coupled hydraulic fracture, reservoir, and wellbore simulator, and flowing pressure responses in the presence of a fault are illustrated. The practical application of the proposed method is demonstrated using DFIT-FBA field examples performed in a tight reservoir. Analysis of the field examples leads to the conclusion that a fault likely occurs near the toe of the horizontal lateral. This finding was confirmed by other field information and provides the opportunity to modify the main-stage hydraulic fracturing design to avoid induced seismicity events.
{"title":"Fault Identification for the Purposes of Evaluating the Risk of Induced Seismicity: A Novel Application of the Flowback DFIT","authors":"D. Zeinabady, C. R. Clarkson, S. Razzaghi, S. Haqparast, A. L. Benson, M. Azad","doi":"10.2118/211100-pa","DOIUrl":"https://doi.org/10.2118/211100-pa","url":null,"abstract":"Summary The existence of faults, pre-existing hydraulic fractures, and depleted areas can negatively impact the development of unconventional reservoirs using multifractured horizontal wells (MFHWs). For example, the triggering of fault slippage through hydraulic fracturing can create the environmental hazard known as induced seismicity (earthquakes caused by hydraulic fracturing). A premium has therefore been placed on the development of technologies that can be used to identify the locations of fault systems (particularly if they are subseismic) as well as pre-existing hydraulic fractures and depleted areas. The objective of this study is to develop a diagnostic tool to identify these conditions using DFIT-FBA, a modified diagnostic fracture injection test (DFIT) with flowback analysis (FBA). The time and cost efficiencies of the DFIT-FBA method in reservoir characterization provides an opportunity to conduct multiple field tests at a single point or along the lateral section of a horizontal well. An analytical model that considers critical processes and mechanisms occurring during DFIT-FBA was first developed herein. The results of analytical modeling demonstrate that reservoir heterogeneities (i.e., faults) can be identified either by implementing multiple cycles of the DFIT-FBA method at a single point or by applying multiple DFIT-FBAs at different points along the lateral section of a horizontal well or at different wells. The analytical model is then verified using a fully coupled hydraulic fracture, reservoir, and wellbore simulator, and flowing pressure responses in the presence of a fault are illustrated. The practical application of the proposed method is demonstrated using DFIT-FBA field examples performed in a tight reservoir. Analysis of the field examples leads to the conclusion that a fault likely occurs near the toe of the horizontal lateral. This finding was confirmed by other field information and provides the opportunity to modify the main-stage hydraulic fracturing design to avoid induced seismicity events.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135998053","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary In this study, we present a novel application of our newly developed physics-based data-driven interwell numerical simulator (INSIM) referred to as INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and bottomhole pressure (BHP) data acquired daily in multiperforated wells produced from an oil reservoir with bottomwater drive mechanism. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. It delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. Our new version represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual timesteps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new feature of our simulator is the use of time-variant well indices and skin factors within the simulator’s well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. Another novel modification has been made to the wellhead term calculation to better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut in. We compare the accuracy of the history-matched oil rate and BHP data and forecasted results as well as computational efficiency for history matching and future prediction by INSIM-BHP with those from a high-fidelity commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells' oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules and changing operational conditions reflected as skin effects at the wells. Besides, it can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a high-fidelity commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that our physics-based, data-driven simulator is about two orders of magnitude faster than a conventional high-fidelity reservoir simulator for a single forward simulation. The specific field application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.
{"title":"History-Matching and Forecasting Production Rate and Bottomhole Pressure Data Using an Enhanced Physics-Based Data-Driven Simulator","authors":"Ying Li, Faruk Omer Alpak, Vivek Jain, Ranran Lu, Mustafa Onur","doi":"10.2118/210102-pa","DOIUrl":"https://doi.org/10.2118/210102-pa","url":null,"abstract":"Summary In this study, we present a novel application of our newly developed physics-based data-driven interwell numerical simulator (INSIM) referred to as INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and bottomhole pressure (BHP) data acquired daily in multiperforated wells produced from an oil reservoir with bottomwater drive mechanism. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. It delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. Our new version represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual timesteps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new feature of our simulator is the use of time-variant well indices and skin factors within the simulator’s well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. Another novel modification has been made to the wellhead term calculation to better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut in. We compare the accuracy of the history-matched oil rate and BHP data and forecasted results as well as computational efficiency for history matching and future prediction by INSIM-BHP with those from a high-fidelity commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells' oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules and changing operational conditions reflected as skin effects at the wells. Besides, it can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a high-fidelity commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that our physics-based, data-driven simulator is about two orders of magnitude faster than a conventional high-fidelity reservoir simulator for a single forward simulation. The specific field application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136321776","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Kuzina, D. Nurgaliev, C. Yuan, V. Morozov, M. Varfolomeev, E. Utemov, L. Chen, J. Pan, W. Pu
In-situ combustion (ISC) has been proven as a promising technique for the extraction of heavy oils. It has been used in oil fields since the 1920s; however, it is still not as widely used as steam injection. One of the difficulties limiting its wide application is monitoring and controlling the movement of the combustion front. This work is aimed at studying the change in the properties of rock during the ISC process, which is expected to be used for developing an effective monitoring method of the combustion front movement. Rock samples before and after the ISC process were obtained from the Xinjiang Oil field (China) where an ISC industrial pilot has been implemented. In the temperature range of lower than 500℃, the minerals may only alter slightly. Therefore, it is difficult to determine whether the rock was heated or not during the ISC processes using general mineralogical or geochemical methods, for example, X-ray diffraction. This work takes a comprehensive approach to study the variation of rock properties. Magnetic analysis was chosen as the primary method since a very tiny change in the mineral composition during heating leads to profound changes in the magnetic properties. We analyzed magnetic susceptibility (MS), natural remanent magnetization (NRM), hysteresis parameters and thermomagnetic data. In addition, we performed differential thermomagnetic analysis (DTMA) for tracing magnetic minerals based on their Curie temperatures as well as for monitoring transformations in magnetic minerals during heating. Simultaneously, X-ray diffractometer (XRD), optical microscope for thin-sections, and organic content measurements were used as assistive methods to get a comprehensive evaluation on the variation of rock. We found that there is a big difference in magnetic minerals between the initial samples (not subjected to the ISC process) and burned samples from different wells and depths in the ISC pilot. Several magnetic clusters with different coercive force and domain structure were found in these samples. Based on the difference in magnetic properties, we found that the burned samples were heated to different temperatures during the ISC process. In addition, for some rock samples, the heating temperature during the ISC process was determined, and an analysis was made of the propagation of the combustion front. The thermal magnetic properties variation of rock during the ISC process is obvious, which makes it promising to be used for monitoring the propagation direction of the combustion front. Theoretical calculations of magnetic anomalies that occur due to changes in the magnetic properties of rocks during the ISC process indicate the possibility of the detection of such anomalies from the Earth’s surface through high-precision magnetic surveys. The findings in this work provide a theoretical base and direction for developing combustion front monitoring technologies.
{"title":"Thermal Magnetic Properties Variation of Rock During In-Situ Combustion Process","authors":"D. Kuzina, D. Nurgaliev, C. Yuan, V. Morozov, M. Varfolomeev, E. Utemov, L. Chen, J. Pan, W. Pu","doi":"10.2118/214296-pa","DOIUrl":"https://doi.org/10.2118/214296-pa","url":null,"abstract":"\u0000 In-situ combustion (ISC) has been proven as a promising technique for the extraction of heavy oils. It has been used in oil fields since the 1920s; however, it is still not as widely used as steam injection. One of the difficulties limiting its wide application is monitoring and controlling the movement of the combustion front. This work is aimed at studying the change in the properties of rock during the ISC process, which is expected to be used for developing an effective monitoring method of the combustion front movement.\u0000 Rock samples before and after the ISC process were obtained from the Xinjiang Oil field (China) where an ISC industrial pilot has been implemented. In the temperature range of lower than 500℃, the minerals may only alter slightly. Therefore, it is difficult to determine whether the rock was heated or not during the ISC processes using general mineralogical or geochemical methods, for example, X-ray diffraction. This work takes a comprehensive approach to study the variation of rock properties. Magnetic analysis was chosen as the primary method since a very tiny change in the mineral composition during heating leads to profound changes in the magnetic properties. We analyzed magnetic susceptibility (MS), natural remanent magnetization (NRM), hysteresis parameters and thermomagnetic data. In addition, we performed differential thermomagnetic analysis (DTMA) for tracing magnetic minerals based on their Curie temperatures as well as for monitoring transformations in magnetic minerals during heating. Simultaneously, X-ray diffractometer (XRD), optical microscope for thin-sections, and organic content measurements were used as assistive methods to get a comprehensive evaluation on the variation of rock.\u0000 We found that there is a big difference in magnetic minerals between the initial samples (not subjected to the ISC process) and burned samples from different wells and depths in the ISC pilot. Several magnetic clusters with different coercive force and domain structure were found in these samples. Based on the difference in magnetic properties, we found that the burned samples were heated to different temperatures during the ISC process. In addition, for some rock samples, the heating temperature during the ISC process was determined, and an analysis was made of the propagation of the combustion front.\u0000 The thermal magnetic properties variation of rock during the ISC process is obvious, which makes it promising to be used for monitoring the propagation direction of the combustion front. Theoretical calculations of magnetic anomalies that occur due to changes in the magnetic properties of rocks during the ISC process indicate the possibility of the detection of such anomalies from the Earth’s surface through high-precision magnetic surveys. The findings in this work provide a theoretical base and direction for developing combustion front monitoring technologies.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"8 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89015184","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Efficient reservoir models are more desirable for fast-paced reservoir management. Moreover, due to the complexity of flow underground, it is also essential to capture the fundamental physics for model reliability. Although they are fast, pure data-driven models frequently have issues associated with interpretability, physical consistency, and ability to forecast. On the other hand, we have used full-physics simulation models to mimic and investigate hydrocarbon systems for over several decades. However, considering its infrequent model updates related to high model complexity, it is a big challenge to manage reservoirs using full-physics models in short cycles. The objective here is to propose an approach that blends reservoir physics with data-driven models to fit in the framework of dynamic reservoir management. We propose to use a reservoir graph network (RGNet) modeling approach based on a diffusive time-of-flight (DTOF) concept to simulate reservoir behaviors. By assimilating field observation data (such as pressure and rates), an RGNet model can be used for future predictions, scenario studies, and well-control optimizations. By discretizing DTOF of a 3D system with multiple wells, RGNet simplifies the system into a graph network represented by a set of 1D grid blocks that significantly reduces the system complexity and run time. RGNet can also handle multiple flow problems with various types of physics. In this work, we propose to use two methods to develop reliable and parsimonious models scalable to large-scale systems. In addition, we propose a more robust method to assimilate pressure data. We applied the proposed approach to a synthetic and a field example. Two different history-matching algorithms, the ensemble smoother with multiple data assimilation (ES-MDA) and an adjoint-based method, are compared. While ES-MDA provides the capability for uncertainty analysis, an adjoint-based method generally requires fewer simulation runs to generate a posterior model. With the proposed methods for generating interwell connections, RGNet model calibration can be achieved without system redundancy and spurious long-distance well connectivity. Also, by using a more stable pressure-matching technique, we show that pressure data are better matched and reservoir volume is accurately characterized. RGNet provides a novel hybrid physics and data-driven reservoir modeling method to fit in closed-loop reservoir management (CLRM). As RGNet models are combined with fundamental flowing physics, the calibrated model parameters are easy to interpret and understand. An RGNet model runs with far less computational cost than required by a full-physics model, which allows it to be a more practical solution to history match, predict, and optimize real assets.
{"title":"Reservoir Modeling, History Matching, and Characterization with a Reservoir Graph Network Model","authors":"Zhenyu Guo, S. Sankaran, Wenyue Sun","doi":"10.2118/209337-pa","DOIUrl":"https://doi.org/10.2118/209337-pa","url":null,"abstract":"\u0000 Efficient reservoir models are more desirable for fast-paced reservoir management. Moreover, due to the complexity of flow underground, it is also essential to capture the fundamental physics for model reliability. Although they are fast, pure data-driven models frequently have issues associated with interpretability, physical consistency, and ability to forecast. On the other hand, we have used full-physics simulation models to mimic and investigate hydrocarbon systems for over several decades. However, considering its infrequent model updates related to high model complexity, it is a big challenge to manage reservoirs using full-physics models in short cycles. The objective here is to propose an approach that blends reservoir physics with data-driven models to fit in the framework of dynamic reservoir management.\u0000 We propose to use a reservoir graph network (RGNet) modeling approach based on a diffusive time-of-flight (DTOF) concept to simulate reservoir behaviors. By assimilating field observation data (such as pressure and rates), an RGNet model can be used for future predictions, scenario studies, and well-control optimizations. By discretizing DTOF of a 3D system with multiple wells, RGNet simplifies the system into a graph network represented by a set of 1D grid blocks that significantly reduces the system complexity and run time. RGNet can also handle multiple flow problems with various types of physics. In this work, we propose to use two methods to develop reliable and parsimonious models scalable to large-scale systems. In addition, we propose a more robust method to assimilate pressure data.\u0000 We applied the proposed approach to a synthetic and a field example. Two different history-matching algorithms, the ensemble smoother with multiple data assimilation (ES-MDA) and an adjoint-based method, are compared. While ES-MDA provides the capability for uncertainty analysis, an adjoint-based method generally requires fewer simulation runs to generate a posterior model. With the proposed methods for generating interwell connections, RGNet model calibration can be achieved without system redundancy and spurious long-distance well connectivity. Also, by using a more stable pressure-matching technique, we show that pressure data are better matched and reservoir volume is accurately characterized.\u0000 RGNet provides a novel hybrid physics and data-driven reservoir modeling method to fit in closed-loop reservoir management (CLRM). As RGNet models are combined with fundamental flowing physics, the calibrated model parameters are easy to interpret and understand. An RGNet model runs with far less computational cost than required by a full-physics model, which allows it to be a more practical solution to history match, predict, and optimize real assets.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"2 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86343404","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Kobayashi, A. Goto, X. Feng, K. Uruma, Y. Momoi, S. Watanabe, K. Sato, Y. Zhang, R. Horne, T. Shibuya, Y. Okano
Microbial DNA-based monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNA-based monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNA-based monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields.
{"title":"Long-Term Microbial DNA-Based Monitoring of the Mature Sarukawa Oil Field in Japan","authors":"H. Kobayashi, A. Goto, X. Feng, K. Uruma, Y. Momoi, S. Watanabe, K. Sato, Y. Zhang, R. Horne, T. Shibuya, Y. Okano","doi":"10.2118/214313-pa","DOIUrl":"https://doi.org/10.2118/214313-pa","url":null,"abstract":"\u0000 Microbial DNA-based monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNA-based monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNA-based monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"7 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84967381","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Amaar Siyal, Khurshed Rahimov, W. Alameri, E. Al-Shalabi, Shehzad Ahmed
Various enhanced oil recovery (EOR) methods are applied after primary and secondary recovery stages to target remaining oil saturation (ROS). This remaining oil is divided into bypassed oil and capillary-trapped residual oil. Mobilizing the residual oil in the reservoir is usually achieved when viscous or gravity forces exceed capillary forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). To optimize the design of various EOR methods in carbonate and sandstone reservoirs, a fundamental understanding of CDC is needed. A thorough and well-documented research study has been performed for determining the residual oil and generating CDC in sandstone rocks. However, a very limited amount of work has been reported on carbonate rocks. Thus, the main objective of this paper is to provide the recent development made over the last few decades on the CDC studies for carbonate and sandstone reservoirs. Different CDC studies were discussed based on the trapping/bond/capillary number and were critically analyzed. Furthermore, the effects of different controlling factors—wettability, permeability, interfacial tension (IFT), and heterogeneity—on CDC were investigated. This review analysis indicates that CDC in carbonate rocks is broader as opposed to sandstone rocks. This is because of the presence of micropores, large pore size distribution, complex geological characteristics, chemical reactivity, mixed-to-oil-wet characteristics, and heterogeneity of carbonate rocks. Moreover, the critical capillary number for water injection in carbonate rocks reported in the literature lies between 10–8 and 10–5. On the other hand, for sandstone rocks, the number ranges between 10–5 and 10–2. Furthermore, a major influence of wettability on the shape of the CDC was observed. The CDC shape is broader for oil-wet rocks, and capillary number values are higher compared to water-wet and mixed-wet rocks. On the other hand, the lowest capillary number values are observed in water-wet rocks. The outcome of this research study will provide a way forward for CDC studies in both sandstone and carbonate rocks. Additionally, it will serve as a baseline for understanding various CDCs and hence better screening of various EOR methods for different types of reservoir rocks.
{"title":"A Comprehensive Review on the Capillary Desaturation Curves for Sandstone and Carbonate Reservoirs","authors":"Amaar Siyal, Khurshed Rahimov, W. Alameri, E. Al-Shalabi, Shehzad Ahmed","doi":"10.2118/207595-pa","DOIUrl":"https://doi.org/10.2118/207595-pa","url":null,"abstract":"\u0000 Various enhanced oil recovery (EOR) methods are applied after primary and secondary recovery stages to target remaining oil saturation (ROS). This remaining oil is divided into bypassed oil and capillary-trapped residual oil. Mobilizing the residual oil in the reservoir is usually achieved when viscous or gravity forces exceed capillary forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). To optimize the design of various EOR methods in carbonate and sandstone reservoirs, a fundamental understanding of CDC is needed. A thorough and well-documented research study has been performed for determining the residual oil and generating CDC in sandstone rocks. However, a very limited amount of work has been reported on carbonate rocks. Thus, the main objective of this paper is to provide the recent development made over the last few decades on the CDC studies for carbonate and sandstone reservoirs. Different CDC studies were discussed based on the trapping/bond/capillary number and were critically analyzed. Furthermore, the effects of different controlling factors—wettability, permeability, interfacial tension (IFT), and heterogeneity—on CDC were investigated.\u0000 This review analysis indicates that CDC in carbonate rocks is broader as opposed to sandstone rocks. This is because of the presence of micropores, large pore size distribution, complex geological characteristics, chemical reactivity, mixed-to-oil-wet characteristics, and heterogeneity of carbonate rocks. Moreover, the critical capillary number for water injection in carbonate rocks reported in the literature lies between 10–8 and 10–5. On the other hand, for sandstone rocks, the number ranges between 10–5 and 10–2. Furthermore, a major influence of wettability on the shape of the CDC was observed. The CDC shape is broader for oil-wet rocks, and capillary number values are higher compared to water-wet and mixed-wet rocks. On the other hand, the lowest capillary number values are observed in water-wet rocks. The outcome of this research study will provide a way forward for CDC studies in both sandstone and carbonate rocks. Additionally, it will serve as a baseline for understanding various CDCs and hence better screening of various EOR methods for different types of reservoir rocks.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"40 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79019423","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Chen-xia Hu, C. Han, Jijun Tian, Zhiqiang Fu, Jinghui Ma, T. Algeo
Tight oil, present in reservoirs of low porosity and permeability, can be regarded as a kind of unconventional resource. The tightening process in this kind of reservoir is controlled by the lithology and diagenetic history of the host formation. Upper Triassic Yanchang Formation siltstones and sandstones are the main reservoirs for hydrocarbon accumulation in the Heshui Oil Field (HOF), southwestern Ordos Basin. The reservoirs exhibit low porosity, low permeability, and strong heterogeneity. In recent years, numerous drillcores have been recovered from these units, but the porosity-permeability characteristics and burial history of these silty and sandy reservoirs have not yet been reported in detail. In this study, an integrated analysis of the lithofacies, diagenesis, and reservoir characteristics of the siltstones and sandstones was achieved using a combination of core and thin section, grain size, scanning electron microscopy (SEM), X-ray diffraction (XRD), δ13C and δ18O, mercury intrusion capillary pressure (MICP), and porosity and permeability data. Our primary goals were to quantify the porosity-permeability characteristics of these silty and sandy reservoirs, restore their diagenetic histories, and examine the paragenetic relationship of reservoir tightness to hydrocarbon accumulation. The silty and sandy reservoirs represent braided river delta facies consisting of compositionally and texturally immature sediments. In the burial environment, they underwent complex diagenetic processes that reduced porosity from an initial average of ~38% to the present ~8%. Porosity-destructive processes included compaction (~ –12.5%) and cementation (~ –21%), with increases in porosity related to grain dissolution (~ +2.2%) and tectonic fractures (~ +1.1%). The reservoirs underwent four diagenetic stages: (1) Penesyngenetic and Eogenetic A Stage (Late Triassic-Early Jurassic); (2) Eogenetic B Stage (Late Jurassic); (3) Early Mesogenetic A Stage (Early Cretaceous); and (4) Late Mesogenetic A Stage (Late Cretaceous to recent). Hydrocarbon charging of these reservoirs occurred in three pulses. Existing pore space was partly filled by hydrocarbons during the Eogenetic B Stage. A second hydrocarbon charging event occurred during the Early Mesogenetic A Stage, when residual primary intergranular pores and secondary dissolution pores were filled. A third hydrocarbon charging event occurred during the Late Mesogenetic A Stage, when the reservoirs were tight. Siltstone beds deposited in delta front environments are the main future exploration targets in the Chang 6 to 8 members. The results of this study provide a useful reference framework for future exploration of hydrocarbon resources in the Upper Triassic Yanchang Formation of the HOF, as well as potential insights into the evolution of similarly tight reservoirs in other basins.
{"title":"Lithofacies and Diagenetic Controls on Tight Silty and Sandy Upper Triassic Reservoirs of the Heshui Oil Field (Ordos Basin, North China)","authors":"Chen-xia Hu, C. Han, Jijun Tian, Zhiqiang Fu, Jinghui Ma, T. Algeo","doi":"10.2118/214289-pa","DOIUrl":"https://doi.org/10.2118/214289-pa","url":null,"abstract":"Tight oil, present in reservoirs of low porosity and permeability, can be regarded as a kind of unconventional resource. The tightening process in this kind of reservoir is controlled by the lithology and diagenetic history of the host formation. Upper Triassic Yanchang Formation siltstones and sandstones are the main reservoirs for hydrocarbon accumulation in the Heshui Oil Field (HOF), southwestern Ordos Basin. The reservoirs exhibit low porosity, low permeability, and strong heterogeneity. In recent years, numerous drillcores have been recovered from these units, but the porosity-permeability characteristics and burial history of these silty and sandy reservoirs have not yet been reported in detail. In this study, an integrated analysis of the lithofacies, diagenesis, and reservoir characteristics of the siltstones and sandstones was achieved using a combination of core and thin section, grain size, scanning electron microscopy (SEM), X-ray diffraction (XRD), δ13C and δ18O, mercury intrusion capillary pressure (MICP), and porosity and permeability data. Our primary goals were to quantify the porosity-permeability characteristics of these silty and sandy reservoirs, restore their diagenetic histories, and examine the paragenetic relationship of reservoir tightness to hydrocarbon accumulation. The silty and sandy reservoirs represent braided river delta facies consisting of compositionally and texturally immature sediments. In the burial environment, they underwent complex diagenetic processes that reduced porosity from an initial average of ~38% to the present ~8%. Porosity-destructive processes included compaction (~ –12.5%) and cementation (~ –21%), with increases in porosity related to grain dissolution (~ +2.2%) and tectonic fractures (~ +1.1%). The reservoirs underwent four diagenetic stages: (1) Penesyngenetic and Eogenetic A Stage (Late Triassic-Early Jurassic); (2) Eogenetic B Stage (Late Jurassic); (3) Early Mesogenetic A Stage (Early Cretaceous); and (4) Late Mesogenetic A Stage (Late Cretaceous to recent). Hydrocarbon charging of these reservoirs occurred in three pulses. Existing pore space was partly filled by hydrocarbons during the Eogenetic B Stage. A second hydrocarbon charging event occurred during the Early Mesogenetic A Stage, when residual primary intergranular pores and secondary dissolution pores were filled. A third hydrocarbon charging event occurred during the Late Mesogenetic A Stage, when the reservoirs were tight. Siltstone beds deposited in delta front environments are the main future exploration targets in the Chang 6 to 8 members. The results of this study provide a useful reference framework for future exploration of hydrocarbon resources in the Upper Triassic Yanchang Formation of the HOF, as well as potential insights into the evolution of similarly tight reservoirs in other basins.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"46 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76045004","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Isabela D. de Albuquerque, S. L. B. Bermúdez, G. C. Stael, C. Rabe, C. Harper
This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.
{"title":"Carbonated Water Injection Effects on Lacustrine Carbonates of Mupe Member, Lower Purbeck Group (Upper Jurassic), United Kingdom","authors":"Isabela D. de Albuquerque, S. L. B. Bermúdez, G. C. Stael, C. Rabe, C. Harper","doi":"10.2118/214304-pa","DOIUrl":"https://doi.org/10.2118/214304-pa","url":null,"abstract":"\u0000 This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"69 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83124711","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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