The relative permeability expresses the mobility reduction factor when a fluid flows through a porous medium in presence of another fluid and appears in Darcy's law for multiphase flow. In this work, we replace Darcy's law with more general momentum equations accounting for fluid-rock interaction (flow resistance), fluid-fluid interaction (drag) and Brinkmann terms responding to gradients in fluid interstitial velocities. By coupling the momentum equations with phase transport equations, we study two important flow processes: forced imbibition (core flooding) and counter-current spontaneous imbibition. In the former a constant water injection rate is applied, and capillary forces neglected, while in the latter, capillary forces drive the process, and the total flux is zero. Our aim is to understand what relative permeabilities result from these systems and flow configurations. From previous work, when using momentum equations without Brinkmann terms, unique saturation dependent relative permeabilities are obtained for the two flow modes that depend on the flow mode. Now, with Brinkmann terms included the relative permeabilities depend on local spatial derivatives of interstitial velocity and pressure. Local relative permeabilities are calculated for both phases utilizing the ratio of phase Darcy velocity and phase pressure gradient. In addition, we utilize the JBN method for forced imbibition to calculate relative permeabilities from pressure drop and average saturation. Both flow setups are parameterized with literature data and sensitivity analysis is performed. During core flooding, Brinkmann terms give a flatter saturation profile and higher front saturation. The saturation profile shape changes with time. Local water relative permeabilities are reduced, while they are slightly raised for oil. The saturation range where relative permeabilities can be evaluated locally is raised and made narrower with increased Brinkmann terms. JBN relative permeabilities deviate from the local values: the trends in curves and saturation range are the same but more pronounced as they incorporate average measurements including the strong impact at the inlet. Brinkmann effects vanish after sufficient distance traveled resulting in the unique saturation functions as a limit. Unsteady state relative permeabilities (based on transient data from single phase injection) differ from steady state relative permeabilities (based on steady state data from co-injection of two fluids) because the Brinkmann terms are zero at steady state. During spontaneous imbibition, higher effect from the Brinkmann terms caused oil relative permeabilities to decrease at low water saturations and slightly increase at high saturations, while water relative permeability was only slightly reduced. The net effect was a delay of the imbibition profile. Local relative permeabilities approached the unique saturation functions without Brinkmann terms deeper in the system because phase velocities
{"title":"Effective Relative Permeabilities Based on Momentum Equations with Brinkmann Terms and Viscous Coupling","authors":"Yangyang Qiao, P. Andersen, Sadegh Ahmadpour","doi":"10.2118/214388-ms","DOIUrl":"https://doi.org/10.2118/214388-ms","url":null,"abstract":"The relative permeability expresses the mobility reduction factor when a fluid flows through a porous medium in presence of another fluid and appears in Darcy's law for multiphase flow. In this work, we replace Darcy's law with more general momentum equations accounting for fluid-rock interaction (flow resistance), fluid-fluid interaction (drag) and Brinkmann terms responding to gradients in fluid interstitial velocities. By coupling the momentum equations with phase transport equations, we study two important flow processes: forced imbibition (core flooding) and counter-current spontaneous imbibition. In the former a constant water injection rate is applied, and capillary forces neglected, while in the latter, capillary forces drive the process, and the total flux is zero. Our aim is to understand what relative permeabilities result from these systems and flow configurations.\u0000 From previous work, when using momentum equations without Brinkmann terms, unique saturation dependent relative permeabilities are obtained for the two flow modes that depend on the flow mode. Now, with Brinkmann terms included the relative permeabilities depend on local spatial derivatives of interstitial velocity and pressure. Local relative permeabilities are calculated for both phases utilizing the ratio of phase Darcy velocity and phase pressure gradient. In addition, we utilize the JBN method for forced imbibition to calculate relative permeabilities from pressure drop and average saturation. Both flow setups are parameterized with literature data and sensitivity analysis is performed.\u0000 During core flooding, Brinkmann terms give a flatter saturation profile and higher front saturation. The saturation profile shape changes with time. Local water relative permeabilities are reduced, while they are slightly raised for oil. The saturation range where relative permeabilities can be evaluated locally is raised and made narrower with increased Brinkmann terms. JBN relative permeabilities deviate from the local values: the trends in curves and saturation range are the same but more pronounced as they incorporate average measurements including the strong impact at the inlet. Brinkmann effects vanish after sufficient distance traveled resulting in the unique saturation functions as a limit. Unsteady state relative permeabilities (based on transient data from single phase injection) differ from steady state relative permeabilities (based on steady state data from co-injection of two fluids) because the Brinkmann terms are zero at steady state. During spontaneous imbibition, higher effect from the Brinkmann terms caused oil relative permeabilities to decrease at low water saturations and slightly increase at high saturations, while water relative permeability was only slightly reduced. The net effect was a delay of the imbibition profile. Local relative permeabilities approached the unique saturation functions without Brinkmann terms deeper in the system because phase velocities","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125396184","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}
A new approach to acidizing is presented where an inert dry chemical is hermetically sealed inside a metal carrier and deployed downhole via E-line or slickline. The tool is spotted in front of the zone of interest and an exothermic reaction is initiated generating hot acid vapour. A depleted Eocene sandstone reservoir with a 2 7/8″ tubing inside 6 5/8″ casing was successfully treated leading to sustained production enhancement in addition to significant carbon footprint reduction when compared to a conventional treatment. The treatment approach, production results and description of the CO2 reduction is presented. A rigorous well candidate selection process was done as part of the treatment design which analyzed information including damage mechanism, well completion architecture, mineralogy, well deviation, formation type and compatibility. Based on this analysis, the tool type and tool placement sequence were determined to optimize the stimulation. For this well, two 2″ HCl and two 2″ 12:3 HCl/HF tools were used to treat a 5.5 m perforated interval. The HCl tools served as pre-flush treatment and removed any scale. This was followed by 12:3 HCl/HF tools which stimulated the near wellbore matrix and ultimately improved the reservoir fluid influx. After each tool was ignited, a drop in the fluid level was observed. This was positive indication that the acid vapour was enhancing connectivity to the reservoir. When pulled to surface, it was observed that all four tools had ignited and had undergone a complete chemical burn. The well had several tubing and pump changes throughout its long production history. More recently, the well was treated by bullheading EDTA and solvent to re-establish the oil production rate with unsatisfactory long-term production results. Prior to the novel treatment, the well had been producing at 9 – 11 m3/d (gross rate) and 1.8 m3/d of oil. After the application of the novel technique, the production results showed a return to the historical rate of 1.8 m3/d of oil (100% increase). Eighteen months post-treatment, the oil production is sustained and producing between 1.5 - 1.6 m3/d. Flow-back equipment was eliminated from the operation since the highly reactive hot acid is fully spent and dissipated. The operation was rigless and the only equipment required was a wireline unit, a crane, and a small fluid truck. The entire stimulation was completed in less than one day and the well could be put immediately back on production. A secondary benefit was a notable reduction in CO2 associated with this treatment method versus a conventional acid treatment. This was achieved by reducing the heavy equipment requirements and the associated diesel consumption.
{"title":"Novel Acid Stimulation Technique for Production Improvement – Austrian Eocene Case Study","authors":"Fraser Troy Smith, Ina Hadziavdic","doi":"10.2118/214416-ms","DOIUrl":"https://doi.org/10.2118/214416-ms","url":null,"abstract":"\u0000 A new approach to acidizing is presented where an inert dry chemical is hermetically sealed inside a metal carrier and deployed downhole via E-line or slickline. The tool is spotted in front of the zone of interest and an exothermic reaction is initiated generating hot acid vapour. A depleted Eocene sandstone reservoir with a 2 7/8″ tubing inside 6 5/8″ casing was successfully treated leading to sustained production enhancement in addition to significant carbon footprint reduction when compared to a conventional treatment. The treatment approach, production results and description of the CO2 reduction is presented. A rigorous well candidate selection process was done as part of the treatment design which analyzed information including damage mechanism, well completion architecture, mineralogy, well deviation, formation type and compatibility. Based on this analysis, the tool type and tool placement sequence were determined to optimize the stimulation. For this well, two 2″ HCl and two 2″ 12:3 HCl/HF tools were used to treat a 5.5 m perforated interval. The HCl tools served as pre-flush treatment and removed any scale. This was followed by 12:3 HCl/HF tools which stimulated the near wellbore matrix and ultimately improved the reservoir fluid influx. After each tool was ignited, a drop in the fluid level was observed. This was positive indication that the acid vapour was enhancing connectivity to the reservoir. When pulled to surface, it was observed that all four tools had ignited and had undergone a complete chemical burn.\u0000 The well had several tubing and pump changes throughout its long production history. More recently, the well was treated by bullheading EDTA and solvent to re-establish the oil production rate with unsatisfactory long-term production results. Prior to the novel treatment, the well had been producing at 9 – 11 m3/d (gross rate) and 1.8 m3/d of oil. After the application of the novel technique, the production results showed a return to the historical rate of 1.8 m3/d of oil (100% increase). Eighteen months post-treatment, the oil production is sustained and producing between 1.5 - 1.6 m3/d. Flow-back equipment was eliminated from the operation since the highly reactive hot acid is fully spent and dissipated. The operation was rigless and the only equipment required was a wireline unit, a crane, and a small fluid truck. The entire stimulation was completed in less than one day and the well could be put immediately back on production.\u0000 A secondary benefit was a notable reduction in CO2 associated with this treatment method versus a conventional acid treatment. This was achieved by reducing the heavy equipment requirements and the associated diesel consumption.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131654958","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Fast Marching Method (FMM) is a highly efficient numerical algorithm frequently used to solve the Eikonal equation to obtain the travel time from the source point to spatial locations, which can generate a geometric description of monotonically advancing front in anisotropic and heterogeneous media. In modeling fluid flow in subsurface heterogeneous porous media, application of the FMM makes the characterization of pressure front propagation quite straightforward using the diffusive time of flight (DTOF) as the Eikonal solution from an asymptotic approximation to the diffusivity equation. For the infinite-acting flow that occurs in smoothly varying heterogeneous media, travel time of pressure front from the active production or injection well to the observation well can be directly estimated from the DTOF using the concept of radius of investigation (ROI). Based on the ROI definition, the travel time to a given location in space can be determined from the maximum magnitude of partial derivative of pressure to time. Treating travel time computed at the observation well as the objective function, we propose a FMM based deep learning (DL) framework, namely the Inversion Neural Network (INN), to inversely estimate heterogeneous reservoir permeability fields through training the deep neural network (DNN) with the travel time data directly generated from the FMM. A convolutional neural network (CNN) is adopted to establish the mapping between the heterogeneous permeability field and the sparse observational data. Because of the quasi-linear relationship between the travel time and reservoir properties, CNN inspired by FMM is able to provide a rapid inverse estimate of heterogeneous reservoir properties that show sufficient accuracy compared to the true reference model with a limited number of observation wells. Inverse modeling results of the permeability fields are validated by the asymptotic pressure approximation through history matching of the reservoir models with the multi-well pressure transient data.
{"title":"Rapid Inference of Reservoir Permeability From Inversion of Travel Time Data Under a Fast Marching Method Based Deep Learning Framework","authors":"Chen Li, Bicheng Yan, Rui Kou, Sunhua Gao","doi":"10.2118/214385-ms","DOIUrl":"https://doi.org/10.2118/214385-ms","url":null,"abstract":"\u0000 The Fast Marching Method (FMM) is a highly efficient numerical algorithm frequently used to solve the Eikonal equation to obtain the travel time from the source point to spatial locations, which can generate a geometric description of monotonically advancing front in anisotropic and heterogeneous media. In modeling fluid flow in subsurface heterogeneous porous media, application of the FMM makes the characterization of pressure front propagation quite straightforward using the diffusive time of flight (DTOF) as the Eikonal solution from an asymptotic approximation to the diffusivity equation. For the infinite-acting flow that occurs in smoothly varying heterogeneous media, travel time of pressure front from the active production or injection well to the observation well can be directly estimated from the DTOF using the concept of radius of investigation (ROI). Based on the ROI definition, the travel time to a given location in space can be determined from the maximum magnitude of partial derivative of pressure to time. Treating travel time computed at the observation well as the objective function, we propose a FMM based deep learning (DL) framework, namely the Inversion Neural Network (INN), to inversely estimate heterogeneous reservoir permeability fields through training the deep neural network (DNN) with the travel time data directly generated from the FMM. A convolutional neural network (CNN) is adopted to establish the mapping between the heterogeneous permeability field and the sparse observational data. Because of the quasi-linear relationship between the travel time and reservoir properties, CNN inspired by FMM is able to provide a rapid inverse estimate of heterogeneous reservoir properties that show sufficient accuracy compared to the true reference model with a limited number of observation wells. Inverse modeling results of the permeability fields are validated by the asymptotic pressure approximation through history matching of the reservoir models with the multi-well pressure transient data.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128157494","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}
Y. Samarkin, A. Amao, M. Aljawad, T. Sølling, M. AlTammar, K. Alruwaili
Fractured carbonate formations composed of chalk and limestone rock lithologies develop several issues over time, reducing fractures’ conductivity. One such issue is the embedment of the proppant that happens due to the soft nature of the carbonate rocks. Reduction of fractures’ conductivity results in the need for refracturing operations that require pumping tremendous amounts of water. The refracturing operations can be avoided if the fractures are maintained conductive for a longer time. This research targets reducing the severity of proppant embedment issues in carbonate formations through rock hardening by diammonium hydrogen phosphate (DAP) treatment. The chalk and limestone rock samples were treated with a DAP solution of 0.8M concentration at three temperatures, namely 30°C (ambient), 50°C, and 80°C. The samples were treated by immersion in solution, in which rocks were kept reacting for 72 hours. The treated samples were analyzed using the SEM-EDX technique to identify new minerals and changes in the morphology of the rock samples. Moreover, the changes in the hardness of the samples were analyzed by the impulse hammering technique. In addition, the proppant embedment scenario was mimicked in the rocks by utilizing Brinell hardness measurements before and after their treatment. The SEM analysis demonstrated that the treatment of carbonate rocks with a DAP solution results in the formation of hydroxyapatite (HAP) minerals. In addition, it was observed that the temperature of the treatment affects the crystallization patterns of the HAP minerals. Further results demonstrated that DAP treatment at elevated temperatures significantly improves the hardness of the samples. Young’s modulus of the rock samples increased by up to 60 - 80% after the treatment. In addition, studies have shown the improvement of rocks’ resistance to indentations. The sizes of the dents created by the Brinell hardness device were smaller than before the treatment. Overall, it was demonstrated that the Brinell hardness of the rock samples improved by more than 100%. This research demonstrated that treating carbonate rocks with DAP solution results in their hardening and improved samples’ resistance to indentation. Moreover, the treatment of rock samples at temperatures similar to reservoir conditions even further improves the mechanical properties of the carbonate rocks. Upscaling laboratory DAP treatment techniques for reservoir applications will introduce new practical methods for maintaining the long-term conductivity of propped fractures. Such a procedure will help avoid refracturing operations, resulting in better and more sustainable management of water resources.
{"title":"High-Temperature DAP Treatments of Carbonate Rocks for Proppant Embedment Severity Mitigation","authors":"Y. Samarkin, A. Amao, M. Aljawad, T. Sølling, M. AlTammar, K. Alruwaili","doi":"10.2118/214368-ms","DOIUrl":"https://doi.org/10.2118/214368-ms","url":null,"abstract":"\u0000 Fractured carbonate formations composed of chalk and limestone rock lithologies develop several issues over time, reducing fractures’ conductivity. One such issue is the embedment of the proppant that happens due to the soft nature of the carbonate rocks. Reduction of fractures’ conductivity results in the need for refracturing operations that require pumping tremendous amounts of water. The refracturing operations can be avoided if the fractures are maintained conductive for a longer time. This research targets reducing the severity of proppant embedment issues in carbonate formations through rock hardening by diammonium hydrogen phosphate (DAP) treatment.\u0000 The chalk and limestone rock samples were treated with a DAP solution of 0.8M concentration at three temperatures, namely 30°C (ambient), 50°C, and 80°C. The samples were treated by immersion in solution, in which rocks were kept reacting for 72 hours. The treated samples were analyzed using the SEM-EDX technique to identify new minerals and changes in the morphology of the rock samples. Moreover, the changes in the hardness of the samples were analyzed by the impulse hammering technique. In addition, the proppant embedment scenario was mimicked in the rocks by utilizing Brinell hardness measurements before and after their treatment.\u0000 The SEM analysis demonstrated that the treatment of carbonate rocks with a DAP solution results in the formation of hydroxyapatite (HAP) minerals. In addition, it was observed that the temperature of the treatment affects the crystallization patterns of the HAP minerals. Further results demonstrated that DAP treatment at elevated temperatures significantly improves the hardness of the samples. Young’s modulus of the rock samples increased by up to 60 - 80% after the treatment. In addition, studies have shown the improvement of rocks’ resistance to indentations. The sizes of the dents created by the Brinell hardness device were smaller than before the treatment. Overall, it was demonstrated that the Brinell hardness of the rock samples improved by more than 100%.\u0000 This research demonstrated that treating carbonate rocks with DAP solution results in their hardening and improved samples’ resistance to indentation. Moreover, the treatment of rock samples at temperatures similar to reservoir conditions even further improves the mechanical properties of the carbonate rocks. Upscaling laboratory DAP treatment techniques for reservoir applications will introduce new practical methods for maintaining the long-term conductivity of propped fractures. Such a procedure will help avoid refracturing operations, resulting in better and more sustainable management of water resources.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129236103","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}
Energy extraction from the Enhanced Geothermal System (EGS) relies on hydraulic fractures or natural fractures to migrate fluid and thus extract heat from surrounding rocks. However, due to the heterogeneity and complex multi-physics nature inside of fracture plane, high-fidelity physics-based forward simulation can be computationally intensive, creating a barrier for efficient reservoir management. A robust and fast optimization framework for maximizing the thermal recovery from EGS is needed. We developed a general reservoir management framework which is combining a low-fidelity forward surrogate model (fl) with gradient-based optimizers to speed up reservoir management process. Thermo-hydro-mechanical (THM) EGS simulation model is developed based on the finite element-based reservoir simulation. We parameterized the fracture aperture and well controls and performed the THM simulation to generate 2500 datasets. Further, we trained two different architectures of deep neural network (DNN) with the datasets to predict the dynamics (pressure and temperature), and this ultimately becomes the forward model to calculate the total net energy. Instead of performing optimization workflow with large amount of simulations from fh, we directly optimize the well control parameters based on geological parameters to the fl. As fl is efficient, accurate and fully differentiable, it is coupled with different gradient-based or gradient-free optimization algorithms to maximize the total net energy by finding the optimum decision parameters. Based on the simulation datasets, we evaluated the impact of fracture aperture on temperature and pressure evolution, and demonstrated that the spatial fracture aperture distribution dominates the thermal front movement. The fracture aperture variation is highly correlated with temperature change in the fracture, which mainly results from thermal stress changes. Compared to the full-fledged physics simulator, our DNN-based forward surrogate model not only provides a computational speedup of around 1500 times, but also brings high predictive accuracy with R2 value 99%. With the aids of the forward model fl, gradient-based optimizers run optimization 10 to 68 times faster than the derivative-free global optimizers. The proposed reservoir management framework shows both efficiency and scalability, which enables each optimization process to be executed in a real-time fashion.
{"title":"A Robust General Physics-Informed Machine Learning Framework for Energy Recovery Optimization in Geothermal Reservoirs","authors":"Zhen Xu, B. Yan, Manojkumar Gudala, Zeeshan Tariq","doi":"10.2118/214352-ms","DOIUrl":"https://doi.org/10.2118/214352-ms","url":null,"abstract":"\u0000 Energy extraction from the Enhanced Geothermal System (EGS) relies on hydraulic fractures or natural fractures to migrate fluid and thus extract heat from surrounding rocks. However, due to the heterogeneity and complex multi-physics nature inside of fracture plane, high-fidelity physics-based forward simulation can be computationally intensive, creating a barrier for efficient reservoir management. A robust and fast optimization framework for maximizing the thermal recovery from EGS is needed.\u0000 We developed a general reservoir management framework which is combining a low-fidelity forward surrogate model (fl) with gradient-based optimizers to speed up reservoir management process. Thermo-hydro-mechanical (THM) EGS simulation model is developed based on the finite element-based reservoir simulation. We parameterized the fracture aperture and well controls and performed the THM simulation to generate 2500 datasets. Further, we trained two different architectures of deep neural network (DNN) with the datasets to predict the dynamics (pressure and temperature), and this ultimately becomes the forward model to calculate the total net energy. Instead of performing optimization workflow with large amount of simulations from fh, we directly optimize the well control parameters based on geological parameters to the fl. As fl is efficient, accurate and fully differentiable, it is coupled with different gradient-based or gradient-free optimization algorithms to maximize the total net energy by finding the optimum decision parameters.\u0000 Based on the simulation datasets, we evaluated the impact of fracture aperture on temperature and pressure evolution, and demonstrated that the spatial fracture aperture distribution dominates the thermal front movement. The fracture aperture variation is highly correlated with temperature change in the fracture, which mainly results from thermal stress changes. Compared to the full-fledged physics simulator, our DNN-based forward surrogate model not only provides a computational speedup of around 1500 times, but also brings high predictive accuracy with R2 value 99%. With the aids of the forward model fl, gradient-based optimizers run optimization 10 to 68 times faster than the derivative-free global optimizers. The proposed reservoir management framework shows both efficiency and scalability, which enables each optimization process to be executed in a real-time fashion.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"92 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123989643","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the results of numerical simulations of hydraulic fracturing in the immediate vicinity of the wellbore. This research aims to identify the primary mechanisms underlying the complexities in both the fracture morphology and propagation of longitudinal fractures. The study shows that the perforation attributes and characteristics, the cement quality, and the reservoir heterogeneity have a significant impact on the resulting morphology and the trajectory of the propagating hydraulic fracture. The study is based on properties and conditions associated with a field study conducted in the Austin Chalk formation, and concludes that the pattern and the dimensions of the perforations are essential factors controlling the fracture initiation pressure and morphology. The results of the simulation studies provide insights into the principles and mechanisms controlling fracture branching and the initiation of longitudinal fractures in the near-wellbore region and can lead to improved operational designs for more effective fracturing treatments.
{"title":"Numerical Investigation of the Primary Mechanisms Leading to Complex Fracture Morphology in the Near-Wellbore Region","authors":"Serhii Kryvenko, G. Moridis, T. A. Blasingame","doi":"10.2118/214403-ms","DOIUrl":"https://doi.org/10.2118/214403-ms","url":null,"abstract":"\u0000 This paper presents the results of numerical simulations of hydraulic fracturing in the immediate vicinity of the wellbore. This research aims to identify the primary mechanisms underlying the complexities in both the fracture morphology and propagation of longitudinal fractures. The study shows that the perforation attributes and characteristics, the cement quality, and the reservoir heterogeneity have a significant impact on the resulting morphology and the trajectory of the propagating hydraulic fracture.\u0000 The study is based on properties and conditions associated with a field study conducted in the Austin Chalk formation, and concludes that the pattern and the dimensions of the perforations are essential factors controlling the fracture initiation pressure and morphology. The results of the simulation studies provide insights into the principles and mechanisms controlling fracture branching and the initiation of longitudinal fractures in the near-wellbore region and can lead to improved operational designs for more effective fracturing treatments.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"62 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128451796","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. Litvak, J. Rosenzweig, Grant Marblestone, S. Matringe, Pengjun Wang
An innovative optimization methodology for field development planning is presented. A new mixed integer optimizer is described. The optimization tool's "user-friendly" plug-in in a commercial reservoir characterization and simulation package is developed, and methodology applications in exploration projects are outlined. An effective methodology is developed to optimize well placement and facility options in oil fields with multiple reservoirs. The optimized field development plan is selected for individual reservoirs from various well placements, well trajectories, injection strategies, and facility scenarios significantly impacting field oil recovery. Multiple subsurface models representing uncertainties in subsurface descriptions are applied in the optimization process. An effective mixed integer optimizer is developed. The optimizer is based on sequential cycles of a) selection of "promising" scenarios changing one decision variable per simulation and b) evaluations of combinations of the "promising" scenarios using Latin Hypercube sampling. The optimization workflow is implemented as a user-friendly plug-in to a commercial package, which allows one to a) define locations and trajectories of potential wells, b) define well placement and facility scenarios, c) run optimization workflows, and d) evaluate optimization results. The developed optimization methodology is successfully applied in several exploration projects. Effectiveness and significant benefits from the optimization applications are demonstrated. This paper can bring significant benefits to the state of knowledge in the petroleum industry by a) describing the novel methodology for optimizing field development scenarios that have significant impacts on oil recovery, b) applying the new optimizer, c) implementing the optimization plug-in in a commercial package.
{"title":"Scenario Based Optimization Methodology for Field Development Planning","authors":"M. Litvak, J. Rosenzweig, Grant Marblestone, S. Matringe, Pengjun Wang","doi":"10.2118/214387-ms","DOIUrl":"https://doi.org/10.2118/214387-ms","url":null,"abstract":"\u0000 An innovative optimization methodology for field development planning is presented. A new mixed integer optimizer is described. The optimization tool's \"user-friendly\" plug-in in a commercial reservoir characterization and simulation package is developed, and methodology applications in exploration projects are outlined.\u0000 An effective methodology is developed to optimize well placement and facility options in oil fields with multiple reservoirs. The optimized field development plan is selected for individual reservoirs from various well placements, well trajectories, injection strategies, and facility scenarios significantly impacting field oil recovery. Multiple subsurface models representing uncertainties in subsurface descriptions are applied in the optimization process. An effective mixed integer optimizer is developed. The optimizer is based on sequential cycles of a) selection of \"promising\" scenarios changing one decision variable per simulation and b) evaluations of combinations of the \"promising\" scenarios using Latin Hypercube sampling.\u0000 The optimization workflow is implemented as a user-friendly plug-in to a commercial package, which allows one to a) define locations and trajectories of potential wells, b) define well placement and facility scenarios, c) run optimization workflows, and d) evaluate optimization results.\u0000 The developed optimization methodology is successfully applied in several exploration projects. Effectiveness and significant benefits from the optimization applications are demonstrated.\u0000 This paper can bring significant benefits to the state of knowledge in the petroleum industry by a) describing the novel methodology for optimizing field development scenarios that have significant impacts on oil recovery, b) applying the new optimizer, c) implementing the optimization plug-in in a commercial package.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127291532","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}
During CO2 injection, cooling and pressure buildup in the near-wellbore may lead to fracturing of the reservoir rock. These fractures affect the injectivity and can have a significant impact on flow assurance. This paper presents the derivation of a quick and simple method to evaluate the onset of thermal fracturing. This paper starts with geomechanics theory and expressions of minimum horizontal stress in depleted reservoirs. It describes the relations between thermo-poro-elastic stress and the criterion for initiation of (thermal) fracturing. The thermal stress part uses a simplified analytical solution of the stresses around the wellbore taking into account differences due to near-wellbore cooling and far-field virgin temperature conditions. A similar methodology is used to accommodate for pressure difference between the near-wellbore area and the far-field. A set of geomechanical and reservoir parameters are used to set-up diagnostic plots for evaluation. Consequences of the difference between the depletion stress path and injection stress path are discussed. Finally, results are compared to numerical reservoir simulation results. A proposed thermal stress correction factor, which accounts for differences between a simple analytical solution and a full-field evaluation, is checked and adjusted by comparing analytical and numerical results. First indications show that this geometrical factor and the derived equivalent cold zone radius holds for many cases. The sensitivity of thermal fracturing for several reservoir and rock parameters is discussed. The analytical method found is quick, simple and generates equivalent results to the numerical simulator and is therefore assumed to be accurate for estimation of the moment of fracture initiation. The resulting diagnostic plots present a quick and simple alternative to geomechanical simulation for evaluating the possibility and moment of fracture initiation. This method can help in early-stage feasibility work and determine if more detailed modelling is needed.
{"title":"An Analytical Method for Estimation of Thermal Fracturing Initiation During CO2 Injection in Depleted Gas Reservoirs","authors":"T. Huijskes, J. D. de Kok","doi":"10.2118/214389-ms","DOIUrl":"https://doi.org/10.2118/214389-ms","url":null,"abstract":"\u0000 During CO2 injection, cooling and pressure buildup in the near-wellbore may lead to fracturing of the reservoir rock. These fractures affect the injectivity and can have a significant impact on flow assurance. This paper presents the derivation of a quick and simple method to evaluate the onset of thermal fracturing.\u0000 This paper starts with geomechanics theory and expressions of minimum horizontal stress in depleted reservoirs. It describes the relations between thermo-poro-elastic stress and the criterion for initiation of (thermal) fracturing. The thermal stress part uses a simplified analytical solution of the stresses around the wellbore taking into account differences due to near-wellbore cooling and far-field virgin temperature conditions. A similar methodology is used to accommodate for pressure difference between the near-wellbore area and the far-field. A set of geomechanical and reservoir parameters are used to set-up diagnostic plots for evaluation. Consequences of the difference between the depletion stress path and injection stress path are discussed. Finally, results are compared to numerical reservoir simulation results.\u0000 A proposed thermal stress correction factor, which accounts for differences between a simple analytical solution and a full-field evaluation, is checked and adjusted by comparing analytical and numerical results. First indications show that this geometrical factor and the derived equivalent cold zone radius holds for many cases. The sensitivity of thermal fracturing for several reservoir and rock parameters is discussed. The analytical method found is quick, simple and generates equivalent results to the numerical simulator and is therefore assumed to be accurate for estimation of the moment of fracture initiation.\u0000 The resulting diagnostic plots present a quick and simple alternative to geomechanical simulation for evaluating the possibility and moment of fracture initiation. This method can help in early-stage feasibility work and determine if more detailed modelling is needed.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"8 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130709223","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}
Yu Li, Huiqing Liu, Chen Luo, Xiaohu Dong, Qing Wang, C. Liu, Zhipeng Wang
Hybrid steam-CO2 flooding, mature technology to enhance oil recovery, promotes the deposition of asphaltene from heavy oil and the CO2-brine-silica interaction to change the wettability of silica surface. The asphaltene deposition can promote lipophilicity of the silica surface while the CO2-brine-silica interaction can enhance its hydrophilicity. Therefore, aiming to study the wettability alteration during hybrid steam-CO2 flooding, we explore the interaction characteristics of CO2 with oil and brine on the silica surface. In this work, a series of experiments are conducted to reveal the wettability alteration of silica by the interaction of CO2 with different fluids under different conditions. The CO2-brine-silica interaction experiments and the CO2-oil-silica experiments are carried out in the temperature and pressure-resistant vessel to comprehensively acquire the silica under the influence of various fluids in the static process. In addition, based on the core flooding experiments, computerized tomography (CT) technology is applied to realistically and automatically extract the dynamic contact angle in the dynamic process. The result of contact angle from CO2-brine-silica interaction experiments shows the interaction between CO2 and brine evidently enhances the hydrophilicity of the silica surface under high temperature, and the ability of CO2 and brine to promote the increase of hydrophilicity is much greater than that in the absence of CO2. Moreover, the result of contact angle from CO2-oil-silica experiments indicates the increase of temperature and CO2 pressure makes the silica surface covered by heavy oil present the tendency of hydrophobia. The micro-CT images from core displacement experiments are automatically processed by an intelligent algorithm to extract the remaining oil distribution and display the data of dynamic contact angle. Under the influence of steam, the remaining oil mainly performs the form of membrane oil attached to the silica surface. Furthermore, the edges of the remaining oil take on an irregular shape and the contact angle reflecting hydrophobicity reach 45.2% after steam flooding. After the stage of CO2 flooding, the obvious reduction in membrane oil thickness occurs and the number of contact angles reflecting hydrophobicity decreases to 35.3%. Moreover, the oil film gradually transforms into many oil droplets on the surface under the steam and CO2, which may be conducive to the migration of heavy oil in a porous medium. Taking static and dynamic characteristics of contact angle into account under different environments, the conditions and mechanism of wettability alteration can serve as a perspective for CO2 application in pore-scale displacement.
{"title":"Discussion on the Wettability Alteration Behavior Induced by CO2-Brine-Silica Interaction and Its Effect on the Performance of Hybrid Steam-CO2 Flooding","authors":"Yu Li, Huiqing Liu, Chen Luo, Xiaohu Dong, Qing Wang, C. Liu, Zhipeng Wang","doi":"10.2118/214436-ms","DOIUrl":"https://doi.org/10.2118/214436-ms","url":null,"abstract":"\u0000 Hybrid steam-CO2 flooding, mature technology to enhance oil recovery, promotes the deposition of asphaltene from heavy oil and the CO2-brine-silica interaction to change the wettability of silica surface. The asphaltene deposition can promote lipophilicity of the silica surface while the CO2-brine-silica interaction can enhance its hydrophilicity. Therefore, aiming to study the wettability alteration during hybrid steam-CO2 flooding, we explore the interaction characteristics of CO2 with oil and brine on the silica surface.\u0000 In this work, a series of experiments are conducted to reveal the wettability alteration of silica by the interaction of CO2 with different fluids under different conditions. The CO2-brine-silica interaction experiments and the CO2-oil-silica experiments are carried out in the temperature and pressure-resistant vessel to comprehensively acquire the silica under the influence of various fluids in the static process. In addition, based on the core flooding experiments, computerized tomography (CT) technology is applied to realistically and automatically extract the dynamic contact angle in the dynamic process.\u0000 The result of contact angle from CO2-brine-silica interaction experiments shows the interaction between CO2 and brine evidently enhances the hydrophilicity of the silica surface under high temperature, and the ability of CO2 and brine to promote the increase of hydrophilicity is much greater than that in the absence of CO2. Moreover, the result of contact angle from CO2-oil-silica experiments indicates the increase of temperature and CO2 pressure makes the silica surface covered by heavy oil present the tendency of hydrophobia. The micro-CT images from core displacement experiments are automatically processed by an intelligent algorithm to extract the remaining oil distribution and display the data of dynamic contact angle. Under the influence of steam, the remaining oil mainly performs the form of membrane oil attached to the silica surface. Furthermore, the edges of the remaining oil take on an irregular shape and the contact angle reflecting hydrophobicity reach 45.2% after steam flooding. After the stage of CO2 flooding, the obvious reduction in membrane oil thickness occurs and the number of contact angles reflecting hydrophobicity decreases to 35.3%. Moreover, the oil film gradually transforms into many oil droplets on the surface under the steam and CO2, which may be conducive to the migration of heavy oil in a porous medium.\u0000 Taking static and dynamic characteristics of contact angle into account under different environments, the conditions and mechanism of wettability alteration can serve as a perspective for CO2 application in pore-scale displacement.","PeriodicalId":388039,"journal":{"name":"Day 3 Wed, June 07, 2023","volume":"179 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123030209","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：