Xupeng He, M. AlSinan, Zhen Zhang, H. Kwak, H. Hoteit
Coupling flow with geomechanical processes at the pore scale in fractured rocks is essential in understanding the macroscopic processes of interest, such as geothermal energy extraction, CO2 sequestration, and hydrocarbon production from naturally and hydraulically fractured reservoirs. To investigate the microscopic (pore-scale) phenomena, we propose an efficient and accurate flow-geomechanics coupling algorithm to advance the fundamental flow mechanism from the micro-continuum perspective. Further, we investigate the stress influence on fluid leakage caused by matrix-fracture interaction. In this work, we employ a hybrid micro-continuum approach to describe the flow in fractured rocks, in which fracture flow is described by Navier-Stokes (NS) equations and flow in the surrounding matrix is modeled by Darcy's law. This hybrid modeling is achieved using the extended Darcy-Brinkman-Stokes (EDBS) equations. This approach applies a unified conservation equation for flow in both media (fracture & matrix). We then couple the EDBS flow model with the Brown-Scholz (BS) geomechanical model, which quantifies the deformation of rock fractures. We demonstrate the accuracy of the coupled flow-geomechanical algorithm, in which the accuracy of the EDBS flow model is validated by a simple case with a known analytical solution. The BS geomechanical model is demonstrated with experimental data collected from the literature. The developed flow-geomechanical coupling algorithm is then used to perform sensitivity analyses to explore the factors impacting the fluid leakage caused by the matrix-fracture interaction. We found that the degree of fluid leakage increases as matrix permeability increases and fractures become rougher. Fluid leakage degree decreases with the increase of inertial forces because of the existence of eddies, which prevents the flux exchange between the matrix and fracture. We also investigate the stress influence on fluid leakage and further on fracture permeability under the impact of matrix-fracture interaction. We conclude the fracture permeability would increase with the consideration of the fluid leakage and exhibits an exponential relation with the effective stress.
{"title":"Micro-Continuum Approach for Modeling Coupled Flow and Geomechanical Processes in Fractured Rocks","authors":"Xupeng He, M. AlSinan, Zhen Zhang, H. Kwak, H. Hoteit","doi":"10.2118/210453-ms","DOIUrl":"https://doi.org/10.2118/210453-ms","url":null,"abstract":"\u0000 Coupling flow with geomechanical processes at the pore scale in fractured rocks is essential in understanding the macroscopic processes of interest, such as geothermal energy extraction, CO2 sequestration, and hydrocarbon production from naturally and hydraulically fractured reservoirs. To investigate the microscopic (pore-scale) phenomena, we propose an efficient and accurate flow-geomechanics coupling algorithm to advance the fundamental flow mechanism from the micro-continuum perspective. Further, we investigate the stress influence on fluid leakage caused by matrix-fracture interaction. In this work, we employ a hybrid micro-continuum approach to describe the flow in fractured rocks, in which fracture flow is described by Navier-Stokes (NS) equations and flow in the surrounding matrix is modeled by Darcy's law. This hybrid modeling is achieved using the extended Darcy-Brinkman-Stokes (EDBS) equations. This approach applies a unified conservation equation for flow in both media (fracture & matrix). We then couple the EDBS flow model with the Brown-Scholz (BS) geomechanical model, which quantifies the deformation of rock fractures. We demonstrate the accuracy of the coupled flow-geomechanical algorithm, in which the accuracy of the EDBS flow model is validated by a simple case with a known analytical solution. The BS geomechanical model is demonstrated with experimental data collected from the literature. The developed flow-geomechanical coupling algorithm is then used to perform sensitivity analyses to explore the factors impacting the fluid leakage caused by the matrix-fracture interaction. We found that the degree of fluid leakage increases as matrix permeability increases and fractures become rougher. Fluid leakage degree decreases with the increase of inertial forces because of the existence of eddies, which prevents the flux exchange between the matrix and fracture. We also investigate the stress influence on fluid leakage and further on fracture permeability under the impact of matrix-fracture interaction. We conclude the fracture permeability would increase with the consideration of the fluid leakage and exhibits an exponential relation with the effective stress.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116012046","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}
Automated production monitoring and diagnostics is becoming essential for oil producers to achieve operational efficiency. In this work a combination of unsupervised and supervised machine-learning (ML) models are proposed and were integrated with interactive voice interface so that production diagnostic reports can be generated by using interactive session with chatbot. To achieve this, current work proposes an integration of ML models and chatbot in the cloud native environment and presents a case study using data from hundreds of wells supported on plunger lift system. Within ML framework data preprocessing and principle component analysis (PCA) was performed. The purpose of PCA was to identify principle components (PCs) and the projection production rate data over few dominating PCs and generate 2D or 3D plots which can be used to cluster wells based on production trends and relative performance. Then using daily production data, a regression tree analysis (per well) was performed to predict production rate for dominating phase for production. Regression tree generated if-else type rules which were used for production diagnostics. Further, using early few months of time series data for production, pressure and artificial lift data, another PCA model was trained and contribution chart (per well) were developed to identify which are the most contributing variables towards the change in the production such as increase or decrease in production rate. Finally, to enhance end user experience, a cloud native chatbot leveraging cloud services was configured to perform all steps involved in ML framework in serverless compute environment. The chatbot was built to answer frequently asked production monitoring and diagnostics questions such as "provide me a list of poor performing well" etc. The proposed framework was applied to wells supported on plunger lift and PCA revealed that that four PCs were enough to capture most dominating production modes and first 3 PC described 96.2% of variance. The diagnostic charts were built utilizing 2D and 3D diagrams using projection of gas production rate over first 3 PCs. This was found visually extremely useful to identify which well or group of wells were not performing as expected when compared to rest of the wells. Just by looking 2D plot about 10% wells were found with significant decrease while about 15% were found moderate decrease in production rate. Once identified poorly performing wells regression tree analysis was automatically generated along with the contribution charts for all variables. Couple of case studies were presented using two different wells with contrast production trend and it was demonstrated that the present workflow was able to identify relative behavior of those wells and presented detailed diagnostics using regression tree analysis and contribution charts. Overall, diagnostic charts were able to identify how to calibrate plunger count, plunger velocity, trip time etc. for improved
{"title":"Leveraging Machine Learning and Interactive Voice Interface for Automated Production Monitoring and Diagnostic","authors":"Ajay Singh, Anand Shukla, Suryansh Purwar","doi":"10.2118/210475-ms","DOIUrl":"https://doi.org/10.2118/210475-ms","url":null,"abstract":"\u0000 Automated production monitoring and diagnostics is becoming essential for oil producers to achieve operational efficiency. In this work a combination of unsupervised and supervised machine-learning (ML) models are proposed and were integrated with interactive voice interface so that production diagnostic reports can be generated by using interactive session with chatbot. To achieve this, current work proposes an integration of ML models and chatbot in the cloud native environment and presents a case study using data from hundreds of wells supported on plunger lift system. Within ML framework data preprocessing and principle component analysis (PCA) was performed. The purpose of PCA was to identify principle components (PCs) and the projection production rate data over few dominating PCs and generate 2D or 3D plots which can be used to cluster wells based on production trends and relative performance. Then using daily production data, a regression tree analysis (per well) was performed to predict production rate for dominating phase for production. Regression tree generated if-else type rules which were used for production diagnostics. Further, using early few months of time series data for production, pressure and artificial lift data, another PCA model was trained and contribution chart (per well) were developed to identify which are the most contributing variables towards the change in the production such as increase or decrease in production rate. Finally, to enhance end user experience, a cloud native chatbot leveraging cloud services was configured to perform all steps involved in ML framework in serverless compute environment. The chatbot was built to answer frequently asked production monitoring and diagnostics questions such as \"provide me a list of poor performing well\" etc.\u0000 The proposed framework was applied to wells supported on plunger lift and PCA revealed that that four PCs were enough to capture most dominating production modes and first 3 PC described 96.2% of variance. The diagnostic charts were built utilizing 2D and 3D diagrams using projection of gas production rate over first 3 PCs. This was found visually extremely useful to identify which well or group of wells were not performing as expected when compared to rest of the wells. Just by looking 2D plot about 10% wells were found with significant decrease while about 15% were found moderate decrease in production rate. Once identified poorly performing wells regression tree analysis was automatically generated along with the contribution charts for all variables. Couple of case studies were presented using two different wells with contrast production trend and it was demonstrated that the present workflow was able to identify relative behavior of those wells and presented detailed diagnostics using regression tree analysis and contribution charts. Overall, diagnostic charts were able to identify how to calibrate plunger count, plunger velocity, trip time etc. for improved ","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"94 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123434722","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}
K. Ochie, Moghanloo Rouzbeh, J. Daneshfar, J. Burghardt
This paper examines the application of Bayes’ theorem to evaluate risk of induced seismicity associated with CO2 sequestration in the Arbuckle Formation, which extends across the southern Mid-Continent of the US. Geological storage can effectively contribute to reducing emission of CO2, otherwise released into the atmosphere, achieving the climate goals committed in the 2021 United Nations Climate Change Conference (COP26), however, concerns about risks associated with CO2 injection along with economic challenges of infrastructure required to execute the Carbon Capture Utilization and Storage projects stand against full realization of remarkable potentials. The main goal is usually for CO2 to be stored over geologic time; hence, geomechanical risks such as the seismicity in the field or potential CO2 leakage through seals cannot be ignored and is considered as one of the requirements to determine success of the project. This paper elaborates the risk of potential seismic events that can impact the longevity and success of projects. Accurate risk estimation is key for environmental, economic, and safety concerns and is also one of the requirements to get class VI permits from the US Environmental Protection Agency. We utilized the Bayesian approach, a statistical model where a random probability distribution is used to represent uncertainties within the model, including both input/output parameters. Using Oklahoma as a case study we utilized data from established physics-based models of the system and the details from past observed/monitored failures to evaluate future risk potential for the area. In our approach, we establish the current probability for the state of stress for the area under investigation, then monitor how the state of stress evolves. The stress state probability distribution is calculated to evaluate the probability of activating a critically oriented fault over a range of specified pore pressures. The results suggest that we can estimate the probability of inducing seismicity in the formation. Based on our modelling results, at initial injection pressuresthere is a 30% risk of introducing seismicity in the Arbuckle formation. Based on these results, we went further to conduct a sensitivity analysis to determine the features with multiple predictor dependence on the risk level. In most cases analyzed the risk of induced seismicity by injection is still greater than 30% due to the stress state being very poorly constrained. Introducing stress state constraints from the Arbuckle formation in Kansas State, the risk of seismicity reduced to 10%. Considering the results from our work, operators can optimize the site screening and collect additional data to constrain inherent uncertainties in geomechanical risk evaluation and make informed decisions during operations. The result from this work shows that geological storage of CO2 at reduced rates in the Arbuckle formation can be a feasible safe strategy towards achieving climate
{"title":"A Probability Evaluation of Seismicity Risks Associated with CO2 Injection into Arbuckle Formation","authors":"K. Ochie, Moghanloo Rouzbeh, J. Daneshfar, J. Burghardt","doi":"10.2118/210345-ms","DOIUrl":"https://doi.org/10.2118/210345-ms","url":null,"abstract":"\u0000 This paper examines the application of Bayes’ theorem to evaluate risk of induced seismicity associated with CO2 sequestration in the Arbuckle Formation, which extends across the southern Mid-Continent of the US. Geological storage can effectively contribute to reducing emission of CO2, otherwise released into the atmosphere, achieving the climate goals committed in the 2021 United Nations Climate Change Conference (COP26), however, concerns about risks associated with CO2 injection along with economic challenges of infrastructure required to execute the Carbon Capture Utilization and Storage projects stand against full realization of remarkable potentials. The main goal is usually for CO2 to be stored over geologic time; hence, geomechanical risks such as the seismicity in the field or potential CO2 leakage through seals cannot be ignored and is considered as one of the requirements to determine success of the project.\u0000 This paper elaborates the risk of potential seismic events that can impact the longevity and success of projects. Accurate risk estimation is key for environmental, economic, and safety concerns and is also one of the requirements to get class VI permits from the US Environmental Protection Agency. We utilized the Bayesian approach, a statistical model where a random probability distribution is used to represent uncertainties within the model, including both input/output parameters. Using Oklahoma as a case study we utilized data from established physics-based models of the system and the details from past observed/monitored failures to evaluate future risk potential for the area. In our approach, we establish the current probability for the state of stress for the area under investigation, then monitor how the state of stress evolves. The stress state probability distribution is calculated to evaluate the probability of activating a critically oriented fault over a range of specified pore pressures.\u0000 The results suggest that we can estimate the probability of inducing seismicity in the formation. Based on our modelling results, at initial injection pressuresthere is a 30% risk of introducing seismicity in the Arbuckle formation. Based on these results, we went further to conduct a sensitivity analysis to determine the features with multiple predictor dependence on the risk level. In most cases analyzed the risk of induced seismicity by injection is still greater than 30% due to the stress state being very poorly constrained. Introducing stress state constraints from the Arbuckle formation in Kansas State, the risk of seismicity reduced to 10%.\u0000 Considering the results from our work, operators can optimize the site screening and collect additional data to constrain inherent uncertainties in geomechanical risk evaluation and make informed decisions during operations. The result from this work shows that geological storage of CO2 at reduced rates in the Arbuckle formation can be a feasible safe strategy towards achieving climate ","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122135001","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}
Geothermal (GT) energy has gained much attention as a promising contributor to the energy transition for its capacity to provide a reliable, environmentally friendly source of baseload power. However, drilling high-temperature reservoirs presents significant technical and economic challenges, including thermally induced damage to bits and downhole tools, increasing drilling time and cost. This paper introduces the benefits of drilling heat maps for pro-active temperature management in GT wells during the well planning phase and the real-time drilling operations phase to avoid thermally induced drilling problems. This study uses a transient hydraulic model integrated with a thermal model to predict the bottom hole circulating temperature (BHCT) while drilling GT wells. The model was used to generate a large volume (1000's) of case scenarios to explore the impact of various cooling and other heat management strategies on downhole temperature, covering a wide range of drilling parameters. Results were captured, visualized, and analyzed in convenient heat maps, using the Utah Forge GT field as an example, illustrating the advantages of using such heat maps in GT well construction and real-time operations. Model validation with Forge 16A(78)-32 well data and Hasan and Kabir's well temperature model show very good results, with a mean absolute percentage error (MAPE) of less than 3.2%. There is a clear logarithmic relationship between the drilling flow rate and BHCT at a constant mud inlet temperature, and a linear relationship between the mud inlet temperature and BHCT at a constant drilling flow rate. Pronounced variation of BHCT in GT wells was observed with mud type, mud weight, and mud viscosity. In addition, insulated drill pipe (IDP) technology was found to significantly reduce BHCT (14-44% on average for Forge scenarios) compared to conventional drill pipe (CDP), particularly in wells with extended measured depth where other heat management technologies and strategies become less effective. Drilling heat maps can alert drilling engineers to strategies with the highest BHCT-lowering impact, allowing focused technology selection and decision-making regarding optimum temperature management during the GT well design phase. Real-time heat maps, on the other hand, are valuable for facilitating active temperature management and providing real-time guidance for optimum drilling parameters during daily drilling operations. In general, heat maps can help to avoid drilling problems related to high temperature, thereby helping to facilitate safe and cost-efficient development of GT resources.
{"title":"Drilling Heat Maps for Active Temperature Management in Geothermal Wells","authors":"M. Khaled, Dongmei Chen, P. Ashok, E. van Oort","doi":"10.2118/210306-ms","DOIUrl":"https://doi.org/10.2118/210306-ms","url":null,"abstract":"\u0000 Geothermal (GT) energy has gained much attention as a promising contributor to the energy transition for its capacity to provide a reliable, environmentally friendly source of baseload power. However, drilling high-temperature reservoirs presents significant technical and economic challenges, including thermally induced damage to bits and downhole tools, increasing drilling time and cost. This paper introduces the benefits of drilling heat maps for pro-active temperature management in GT wells during the well planning phase and the real-time drilling operations phase to avoid thermally induced drilling problems.\u0000 This study uses a transient hydraulic model integrated with a thermal model to predict the bottom hole circulating temperature (BHCT) while drilling GT wells. The model was used to generate a large volume (1000's) of case scenarios to explore the impact of various cooling and other heat management strategies on downhole temperature, covering a wide range of drilling parameters. Results were captured, visualized, and analyzed in convenient heat maps, using the Utah Forge GT field as an example, illustrating the advantages of using such heat maps in GT well construction and real-time operations.\u0000 Model validation with Forge 16A(78)-32 well data and Hasan and Kabir's well temperature model show very good results, with a mean absolute percentage error (MAPE) of less than 3.2%. There is a clear logarithmic relationship between the drilling flow rate and BHCT at a constant mud inlet temperature, and a linear relationship between the mud inlet temperature and BHCT at a constant drilling flow rate. Pronounced variation of BHCT in GT wells was observed with mud type, mud weight, and mud viscosity. In addition, insulated drill pipe (IDP) technology was found to significantly reduce BHCT (14-44% on average for Forge scenarios) compared to conventional drill pipe (CDP), particularly in wells with extended measured depth where other heat management technologies and strategies become less effective.\u0000 Drilling heat maps can alert drilling engineers to strategies with the highest BHCT-lowering impact, allowing focused technology selection and decision-making regarding optimum temperature management during the GT well design phase. Real-time heat maps, on the other hand, are valuable for facilitating active temperature management and providing real-time guidance for optimum drilling parameters during daily drilling operations. In general, heat maps can help to avoid drilling problems related to high temperature, thereby helping to facilitate safe and cost-efficient development of GT resources.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125811452","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}
Ao Li, Hongquan Chen, A. Datta-Gupta, A. Chitale, Sunit Shekher, Vivek Shankar, M. Kumar, A. Ahmed, Joyjit Das, Ritesh Kumar
Mangala field (India) is one of the largest polymer flooding fields in the world with hundreds of wells and waxy crude oil. Field-scale optimization of polymer injection is challenging due to the geologic heterogeneity and operational constraints. This paper demonstrates an application of streamline-based injection optimization for the Mangala field. The paper will cover the mathematical foundation, optimization studies, and considerations for field implementation. Our field application consists of five key stages: i) Problem framing. This includes defining optimization objectives, tuning parameters and constraints such as optimization start/end times, schedule update intervals, field rate targets, and injection/production limits for each well. ii) Rate optimization by streamline method. The optimizer iteratively reallocates the well rates, diverting the injected fluid to high efficiency injector-producer pairs located in upswept oil regions. iii) Optimal schedule interpretation. The rate change, flow pattern alteration and injection efficiency improvement are systematically examined, providing decision makers physical explanations of the suggested rate changes. iv) Selection of key injectors for field implementation. To avoid the risk of large-scale field implementation, limited number of injectors contributing the most to the oil production increase or water production decrease are selected for initial deployment. v) Potential field implementation and validation of the proposed plan based on field observations. Data from offset producers surrounding the rate-reallocated injectors can help evaluate oil production improvement or alleviated decline. The optimized rate schedule is first compared with the current schedule in the field, honoring the field total liquid injection/production rates. The optimized case redistributes the rate allocation among high efficiency injectors within predefined bottom hole pressure and rate constraints. The cumulative oil production increase for the short-term optimization period, 11 months, is 0.66 MMbbl. The efficiency plots show efficient utilization of injected fluid after optimization and the bubble plots and streamline maps indicate that the optimizer alters the flow pattern for a better sweep of the remaining oil. Based on the full field optimization, 20 key injectors are selected for field implementation. Numerical simulation shows that 75% of total oil gain can be achieved from optimization of the key injectors. For field validation, offset producers are expected to show an arrest in the oil decline rate due to improved pressure support and, also reduced water cut increase after field implementation.
{"title":"Streamline Based Polymerflood Injection Optimization: Experiences in the Mangala Field, India","authors":"Ao Li, Hongquan Chen, A. Datta-Gupta, A. Chitale, Sunit Shekher, Vivek Shankar, M. Kumar, A. Ahmed, Joyjit Das, Ritesh Kumar","doi":"10.2118/209998-ms","DOIUrl":"https://doi.org/10.2118/209998-ms","url":null,"abstract":"\u0000 Mangala field (India) is one of the largest polymer flooding fields in the world with hundreds of wells and waxy crude oil. Field-scale optimization of polymer injection is challenging due to the geologic heterogeneity and operational constraints. This paper demonstrates an application of streamline-based injection optimization for the Mangala field. The paper will cover the mathematical foundation, optimization studies, and considerations for field implementation.\u0000 Our field application consists of five key stages: i) Problem framing. This includes defining optimization objectives, tuning parameters and constraints such as optimization start/end times, schedule update intervals, field rate targets, and injection/production limits for each well. ii) Rate optimization by streamline method. The optimizer iteratively reallocates the well rates, diverting the injected fluid to high efficiency injector-producer pairs located in upswept oil regions. iii) Optimal schedule interpretation. The rate change, flow pattern alteration and injection efficiency improvement are systematically examined, providing decision makers physical explanations of the suggested rate changes. iv) Selection of key injectors for field implementation. To avoid the risk of large-scale field implementation, limited number of injectors contributing the most to the oil production increase or water production decrease are selected for initial deployment. v) Potential field implementation and validation of the proposed plan based on field observations. Data from offset producers surrounding the rate-reallocated injectors can help evaluate oil production improvement or alleviated decline.\u0000 The optimized rate schedule is first compared with the current schedule in the field, honoring the field total liquid injection/production rates. The optimized case redistributes the rate allocation among high efficiency injectors within predefined bottom hole pressure and rate constraints. The cumulative oil production increase for the short-term optimization period, 11 months, is 0.66 MMbbl. The efficiency plots show efficient utilization of injected fluid after optimization and the bubble plots and streamline maps indicate that the optimizer alters the flow pattern for a better sweep of the remaining oil. Based on the full field optimization, 20 key injectors are selected for field implementation. Numerical simulation shows that 75% of total oil gain can be achieved from optimization of the key injectors. For field validation, offset producers are expected to show an arrest in the oil decline rate due to improved pressure support and, also reduced water cut increase after field implementation.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"450 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124628545","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}
Filipe Vidal C. S. R. Soares de Oliveira, Ricardo Tepedino Martins Gomes, Carlos Eduardo Dias Roriz, Krishna Milani Simões Silva, Rafael Correa de Toledo
The present research propouses a methodology using XRF analysis on drill cuttings samples, obtained during well drilling, for characterizing pre-salt reservoir formations in the Santos Basin, southeast of Brazil in order to identify composition variations in carbonates, clay zones and potential igneous rocks. In this study 16 off-set wells were analyzed where XRF analysis was performed on drill cuttings samples. Aftwerwards the results were compared with lithogeochemical and gamma-ray spectral logs, determining the consistency of the data. The lithological interpretations were based on macroscopic (sidewall core samples - SWC) and microscopic (thin section) descriptions and geochemical analyses from SWC samples. This permitted us to comprehend the variations observed in the carbonate reservoir and to identify possible igneous rocks. From the results, a pattern of responses could be established for the XRF method for each lithology within the Pre-salt section, using the major elements (Mg, Ca, Si, k, Fe and Al) and some minor elements and trace elements (Sr, Rb, Y, Zr, Ti, Nb, Ga). The variations of the major elements were best observed in radar and bar charts, that use only the major elements, which enabled the separation of the lithological section into six main sets: limestones, dolomitic carbonates, silicified carbonates, carbonates with magnesian clay, siliciclastic rocks (shale/siltstone/sandstone) and basic igneous rocks (basalt/diabase). For quality control, still during drilling, comparative analysis by three approaches was proposed: a) the systematic comparison of the proportion of elements composing the same mineral, such as Ca and Sr, K and Rb, and Al and Ga; b) the comparison of XRF data with XRD data; and c) comparison with calcimetry data in a cutting sample. Furthermore, in order to support the interpretations, four crossplots (Ca × Si; K.Rb × Al.Zr; Rb × Sr; Zr × Fe) and one crossover (Rb × Sr) were generated aiming to individualize the six lithological types described, as well as diagrams from the literature to identify the igneous rock type. The use of XRF on cuttings to determine lithologies during the drilling of petroleum wells is new in the literature, as well as the proposed quality control, being useful for the characterization of complex reservoirs such as Santos Basin pre-salt, being a methodology already used since 2018 by Petrobras.
{"title":"Lithology Identification Through X-Ray Fluorescence (XRF) Analyses on Drill Cuttings While Drilling in Santos Basin","authors":"Filipe Vidal C. S. R. Soares de Oliveira, Ricardo Tepedino Martins Gomes, Carlos Eduardo Dias Roriz, Krishna Milani Simões Silva, Rafael Correa de Toledo","doi":"10.2118/210151-ms","DOIUrl":"https://doi.org/10.2118/210151-ms","url":null,"abstract":"\u0000 The present research propouses a methodology using XRF analysis on drill cuttings samples, obtained during well drilling, for characterizing pre-salt reservoir formations in the Santos Basin, southeast of Brazil in order to identify composition variations in carbonates, clay zones and potential igneous rocks.\u0000 In this study 16 off-set wells were analyzed where XRF analysis was performed on drill cuttings samples. Aftwerwards the results were compared with lithogeochemical and gamma-ray spectral logs, determining the consistency of the data. The lithological interpretations were based on macroscopic (sidewall core samples - SWC) and microscopic (thin section) descriptions and geochemical analyses from SWC samples. This permitted us to comprehend the variations observed in the carbonate reservoir and to identify possible igneous rocks.\u0000 From the results, a pattern of responses could be established for the XRF method for each lithology within the Pre-salt section, using the major elements (Mg, Ca, Si, k, Fe and Al) and some minor elements and trace elements (Sr, Rb, Y, Zr, Ti, Nb, Ga). The variations of the major elements were best observed in radar and bar charts, that use only the major elements, which enabled the separation of the lithological section into six main sets: limestones, dolomitic carbonates, silicified carbonates, carbonates with magnesian clay, siliciclastic rocks (shale/siltstone/sandstone) and basic igneous rocks (basalt/diabase). For quality control, still during drilling, comparative analysis by three approaches was proposed: a) the systematic comparison of the proportion of elements composing the same mineral, such as Ca and Sr, K and Rb, and Al and Ga; b) the comparison of XRF data with XRD data; and c) comparison with calcimetry data in a cutting sample. Furthermore, in order to support the interpretations, four crossplots (Ca × Si; K.Rb × Al.Zr; Rb × Sr; Zr × Fe) and one crossover (Rb × Sr) were generated aiming to individualize the six lithological types described, as well as diagrams from the literature to identify the igneous rock type.\u0000 The use of XRF on cuttings to determine lithologies during the drilling of petroleum wells is new in the literature, as well as the proposed quality control, being useful for the characterization of complex reservoirs such as Santos Basin pre-salt, being a methodology already used since 2018 by Petrobras.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128467588","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}
Demands are being placed on service companies to provide non-evasive analytical solutions that measure the contribution of individual hydrocarbon streams in a commingled system. This often involves being able to differentiate fluids which have similar compositions. An advanced analytical workflow has been developed which includes chromatographic techniques along with a suite of stable isotope ratio analyses that look at unique Natural Tracers/Markers in individual hydrocarbon or brine streams. This paper will look at how the Natural Tracer methodology can be applied to fingerprinting, production allocation and IOR/EOR projects. A variety of laboratory-based techniques were used to evaluate end member fluids, commingled fluids, and various synthetic blends. Gaseous streams were analyzed using compound specific stable isotope ratio mass spectrometry systems (CS-IRMS) looking at carbon and hydrogen isotopes of the carbon dioxide, methane, ethane, etc. present. Aqueous streams were analyzed using a combination of conventional physiochemical (complete water) and water oxygen and hydrogen stable isotope analysis. Liquid hydrocarbon systems were assessed using conventional high-resolution gas chromatography and 2-dimentional gas chromatography (GCxGC). Analysis of the data includes simple plots to visualize differences between fluid sources and a linear regression analysis to look at the mixing relationships between synthetic blends and commingled field samples. The advanced analytical workflow allowed for the allocation determination of hydrocarbon systems with both similar and contrasting compositions. The GCxGC method, for hydrocarbon liquids, allows for a higher resolution separation where a single peak using conventional gas chromatography can be composed of multiple types of compounds. In this instance the conventional GC and GCxGC yielded comparable allocation results. For gas phase allocation, using carbon and hydrogen isotope ratios (δ13C and δ2H) of methane and ethane yielded linear mixing relationships in the two-production systems that were analyzed. Allocation values were successfully calculated for these binary systems with an outlying datapoint resulting in the client initiating an investigation to confirm flow meter readings. For an IOR/EOR application, the δ13C of methane show sufficient contrast between injected and produced gases that were sampled from a variety of wells. In this instance the gas molar compositions were similar so the only means to identify injection gas breakthrough in producing wells was by the CS-IRMS analysis technique. Complete physiochemical and water isotope ratio (δ18O and δ2H) analysis also show contrasting signatures between injection and produced water. An advanced analytic workflow was developed to incorporate commercially available, non-evasive techniques to production allocation and IOR/EOR projects. For production allocation, this technique will not replace traditional metering but can be used as a
{"title":"Advanced Analytical Tools for Fingerprinting, Production Allocation, & Improved/Enhanced Oil Recovery Monitoring","authors":"J. Swearingen, Yani Carolina Araujo de Itriago","doi":"10.2118/210060-ms","DOIUrl":"https://doi.org/10.2118/210060-ms","url":null,"abstract":"\u0000 Demands are being placed on service companies to provide non-evasive analytical solutions that measure the contribution of individual hydrocarbon streams in a commingled system. This often involves being able to differentiate fluids which have similar compositions. An advanced analytical workflow has been developed which includes chromatographic techniques along with a suite of stable isotope ratio analyses that look at unique Natural Tracers/Markers in individual hydrocarbon or brine streams. This paper will look at how the Natural Tracer methodology can be applied to fingerprinting, production allocation and IOR/EOR projects.\u0000 A variety of laboratory-based techniques were used to evaluate end member fluids, commingled fluids, and various synthetic blends. Gaseous streams were analyzed using compound specific stable isotope ratio mass spectrometry systems (CS-IRMS) looking at carbon and hydrogen isotopes of the carbon dioxide, methane, ethane, etc. present. Aqueous streams were analyzed using a combination of conventional physiochemical (complete water) and water oxygen and hydrogen stable isotope analysis. Liquid hydrocarbon systems were assessed using conventional high-resolution gas chromatography and 2-dimentional gas chromatography (GCxGC). Analysis of the data includes simple plots to visualize differences between fluid sources and a linear regression analysis to look at the mixing relationships between synthetic blends and commingled field samples.\u0000 The advanced analytical workflow allowed for the allocation determination of hydrocarbon systems with both similar and contrasting compositions. The GCxGC method, for hydrocarbon liquids, allows for a higher resolution separation where a single peak using conventional gas chromatography can be composed of multiple types of compounds. In this instance the conventional GC and GCxGC yielded comparable allocation results. For gas phase allocation, using carbon and hydrogen isotope ratios (δ13C and δ2H) of methane and ethane yielded linear mixing relationships in the two-production systems that were analyzed. Allocation values were successfully calculated for these binary systems with an outlying datapoint resulting in the client initiating an investigation to confirm flow meter readings. For an IOR/EOR application, the δ13C of methane show sufficient contrast between injected and produced gases that were sampled from a variety of wells. In this instance the gas molar compositions were similar so the only means to identify injection gas breakthrough in producing wells was by the CS-IRMS analysis technique. Complete physiochemical and water isotope ratio (δ18O and δ2H) analysis also show contrasting signatures between injection and produced water.\u0000 An advanced analytic workflow was developed to incorporate commercially available, non-evasive techniques to production allocation and IOR/EOR projects. For production allocation, this technique will not replace traditional metering but can be used as a","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127356748","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. Khater, T. Mostafa, G. Ooi, M. Ozakin, Mohamed Larbi Zeghlache, H. Bağcı, Shehab Ahmed
Conventional remote field eddy current tools, which are developed for electromagnetic detection of corrosion on metallic pipes, use transmitter and receiver coils that are spaced apart by at least twice the inspected pipe's diameter. This large space and the low operation frequency required for electromagnetic fields to penetrate multiple casings weaken the voltage induced at the receiver. This challenge limits the quality of corrosion detection and characterization. In this work, a three-axis fluxgate magnetometer is used as a receiver to increase the sensitivity and to enable extraction of directional location of defect from measurements taken off axis. The improved sensitivity and the azimuthal detection capability for localized defects are confirmed by simulations and demonstrated experimentally in a single (4-1/2 in.) pipe and double pipes (4-1/2 in. inside a 7 in.) test setups. The limitations of current electromagnetic technologies in characterizing local defects beyond tubing are highlighted and the benefits of the proposed system are discussed.
{"title":"Remote Field Eddy Current System Using Three Axis Fluxgate Magnetometer for Corrosion Inspection","authors":"M. Khater, T. Mostafa, G. Ooi, M. Ozakin, Mohamed Larbi Zeghlache, H. Bağcı, Shehab Ahmed","doi":"10.2118/210454-ms","DOIUrl":"https://doi.org/10.2118/210454-ms","url":null,"abstract":"\u0000 Conventional remote field eddy current tools, which are developed for electromagnetic detection of corrosion on metallic pipes, use transmitter and receiver coils that are spaced apart by at least twice the inspected pipe's diameter. This large space and the low operation frequency required for electromagnetic fields to penetrate multiple casings weaken the voltage induced at the receiver. This challenge limits the quality of corrosion detection and characterization. In this work, a three-axis fluxgate magnetometer is used as a receiver to increase the sensitivity and to enable extraction of directional location of defect from measurements taken off axis. The improved sensitivity and the azimuthal detection capability for localized defects are confirmed by simulations and demonstrated experimentally in a single (4-1/2 in.) pipe and double pipes (4-1/2 in. inside a 7 in.) test setups. The limitations of current electromagnetic technologies in characterizing local defects beyond tubing are highlighted and the benefits of the proposed system are discussed.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"84 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128917097","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}
Injection pressure is a key parameter in the design of a Huff-and-Puff EOR process in organic-rich shales. Reservoir engineering studies have shown that injection pressure and miscibility play a role during Huff-and-Puff EOR. However, during field implementation, the injection pressure is often limited by the number of compressors and in several cases, the gas injected might not reach sufficient pressure to achieve a state of complete miscibility with the oil. These scenarios lead to a condition of partial miscibility or immiscibility which impacts the efficiency of the recovery mechanisms during Huff-and-Puff EOR. The objective of this present study was to quantify experimentally the impact of complete, partial, and immiscible gas injection during Huff-and-Puff EOR in organic-rich shales. For the purpose of this study, we have collected crude oil and wax preserved core samples from the Eagle Ford shale formation. The Eagle Ford shale samples were characterized by measurements of mineralogy, TOC, porosity, pore throat size, and specific surface area. We performed 20 Huff-and-Puff EOR tests in the shale samples at several different injection pressures, using two field gases and an immiscible helium gas. The minimum miscibility pressure (MMP) between the field gases and the crude oil was measured using the vanishing interfacial tension technique. Oil recovery for each Huff-and-Puff EOR cycle was quantified using NMR measurements. The produced hydrocarbon compositions were determined using a multi-step dry Pyrolysis measurement at the end of each Huff-and-Puff EOR test. Our results show that injection pressure is one of the most important factors controlling the oil recovery during Huff-and-Puff EOR in shales using a field gas. We observe a strong linear increase in oil recovery as injection pressure increases. The injection of the field gas in either partially miscible or completely miscible conditions provides significantly larger oil recovery compared to the immiscible gas at the same absolute pressures. The oil recovery is three times larger for the field gas in a completely miscible condition compared to the immiscible gas and two times larger in a partially miscible condition. The multi-step dry Pyrolysis results show a preferential production of light hydrocarbon species regardless of the state of miscibility during Huff-and-Puff EOR. The findings reported in this experimental study will help to optimize the design of field Huff-and-Puff EOR operations in organic-rich shales. The strong linear trend between the injection pressure and the oil recovery factor in the field gas tests can be used for the selection of gas compressors during field implementations. The superior performance of the field gas compared to the immiscible helium gas at the same injection pressures confirms the importance of miscibility during Huff-and-Puff EOR in organic-rich shales.
{"title":"The Impact of Gas-Oil Miscibility on Oil Recovery During Huff-and-Puff EOR in Organic-Rich Shales","authors":"Felipe Cruz, Sidi Mamoudou, A. Tinni","doi":"10.2118/210028-ms","DOIUrl":"https://doi.org/10.2118/210028-ms","url":null,"abstract":"\u0000 Injection pressure is a key parameter in the design of a Huff-and-Puff EOR process in organic-rich shales. Reservoir engineering studies have shown that injection pressure and miscibility play a role during Huff-and-Puff EOR. However, during field implementation, the injection pressure is often limited by the number of compressors and in several cases, the gas injected might not reach sufficient pressure to achieve a state of complete miscibility with the oil. These scenarios lead to a condition of partial miscibility or immiscibility which impacts the efficiency of the recovery mechanisms during Huff-and-Puff EOR. The objective of this present study was to quantify experimentally the impact of complete, partial, and immiscible gas injection during Huff-and-Puff EOR in organic-rich shales.\u0000 For the purpose of this study, we have collected crude oil and wax preserved core samples from the Eagle Ford shale formation. The Eagle Ford shale samples were characterized by measurements of mineralogy, TOC, porosity, pore throat size, and specific surface area. We performed 20 Huff-and-Puff EOR tests in the shale samples at several different injection pressures, using two field gases and an immiscible helium gas. The minimum miscibility pressure (MMP) between the field gases and the crude oil was measured using the vanishing interfacial tension technique. Oil recovery for each Huff-and-Puff EOR cycle was quantified using NMR measurements. The produced hydrocarbon compositions were determined using a multi-step dry Pyrolysis measurement at the end of each Huff-and-Puff EOR test.\u0000 Our results show that injection pressure is one of the most important factors controlling the oil recovery during Huff-and-Puff EOR in shales using a field gas. We observe a strong linear increase in oil recovery as injection pressure increases. The injection of the field gas in either partially miscible or completely miscible conditions provides significantly larger oil recovery compared to the immiscible gas at the same absolute pressures. The oil recovery is three times larger for the field gas in a completely miscible condition compared to the immiscible gas and two times larger in a partially miscible condition. The multi-step dry Pyrolysis results show a preferential production of light hydrocarbon species regardless of the state of miscibility during Huff-and-Puff EOR.\u0000 The findings reported in this experimental study will help to optimize the design of field Huff-and-Puff EOR operations in organic-rich shales. The strong linear trend between the injection pressure and the oil recovery factor in the field gas tests can be used for the selection of gas compressors during field implementations. The superior performance of the field gas compared to the immiscible helium gas at the same injection pressures confirms the importance of miscibility during Huff-and-Puff EOR in organic-rich shales.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"7 7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131054364","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}
Song Haofeng, Ghosh Pinaki, Bowers Annalise, Mohanty K Kishore
Low salinity waterflooding improves displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency, but enhances sweep efficiency. In this work, the synergy between low salinity and polymer flooding is studied for low permeability carbonate rocks. Polymer solutions were consecutively filtered through a 1.2 µm mixed cellulose ester membrane and a 0.4 µm polycarbonate membrane. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10-20 mD. Low salinity polymer flood was carried out using HPAM prepared in diluted seawaters (with modified sulfate concentrations). After extensive water floods, HPAM prepared in the 10 times-diluted seawater produced the same incremental oil recovery (4-5% original oil in place) as the ATBS-polymer AN132 prepared in the seawater. Increasing the sulfate concentration by four- and eight-folds doubled the incremental oil from low salinity polymer floods.
{"title":"Polymer Augmented Low Salinity Flooding in Low Permeability Carbonate Reservoirs","authors":"Song Haofeng, Ghosh Pinaki, Bowers Annalise, Mohanty K Kishore","doi":"10.2118/210233-ms","DOIUrl":"https://doi.org/10.2118/210233-ms","url":null,"abstract":"\u0000 Low salinity waterflooding improves displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency, but enhances sweep efficiency. In this work, the synergy between low salinity and polymer flooding is studied for low permeability carbonate rocks. Polymer solutions were consecutively filtered through a 1.2 µm mixed cellulose ester membrane and a 0.4 µm polycarbonate membrane. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10-20 mD. Low salinity polymer flood was carried out using HPAM prepared in diluted seawaters (with modified sulfate concentrations). After extensive water floods, HPAM prepared in the 10 times-diluted seawater produced the same incremental oil recovery (4-5% original oil in place) as the ATBS-polymer AN132 prepared in the seawater. Increasing the sulfate concentration by four- and eight-folds doubled the incremental oil from low salinity polymer floods.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130765994","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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