Logging-while-drilling (LWD) borehole images are very important data to support formation characterization and drilling operations. The manual interpretation of this data is a time-consuming task, limited by inconsistencies and uncertainties. We propose a deep-learning (DL)-based supervised method to automatically correlate geological features in low-resolution LWD image logs. Additionally, we tested two learning strategies, namely standard learning (SL) and curriculum learning (CL), to critically analyze the differences in the application on both synthetic and field data. Our results show that these DL models can effectively replace manual labor in dip picking but highlight the need for human intervention to validate and classify the correlated features, proving the utility of the semi-automatic paradigm.
{"title":"Efficient Logging-While-Drilling Image Logs Interpretation Using Deep Learning","authors":"Attilio Molossi, G. Roncoroni, M. Pipan","doi":"10.30632/pjv65n3-2024a5","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a5","url":null,"abstract":"Logging-while-drilling (LWD) borehole images are very important data to support formation characterization and drilling operations. The manual interpretation of this data is a time-consuming task, limited by inconsistencies and uncertainties. We propose a deep-learning (DL)-based supervised method to automatically correlate geological features in low-resolution LWD image logs. Additionally, we tested two learning strategies, namely standard learning (SL) and curriculum learning (CL), to critically analyze the differences in the application on both synthetic and field data. Our results show that these DL models can effectively replace manual labor in dip picking but highlight the need for human intervention to validate and classify the correlated features, proving the utility of the semi-automatic paradigm.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"23 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141411019","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 objective of this study is to showcase the key geological and reservoir engineering parameters that influence underground hydrogen storage, demonstrate the value of some petrophysical data, and show how hydrogen storage differs between depleted gas fields and saline aquifers for reservoir and geomechanical modeling. We utilized numerical simulation modeling to create a base-case model of a synthetic reservoir that accurately represented the hydrodynamic conditions relevant to underground hydrogen storage in porous media. A two-step sensitivity analysis was then conducted. Firstly, we identified the critical parameters that significantly influence the storage and flow of hydrogen in porous media. Subsequently, we analyzed the geomechanical impact of underground hydrogen storage. In addition, we compared the behavior of hydrogen storage to natural gas storage. The study showed that the reservoir depth or current pressure, the reservoir dip, and the flow capacity were the top three factors impacting the optimal withdrawal of hydrogen. The study also revealed that rock displacement and stress changes were important to be monitored, while changes in strain were not significant. If it is assumed that injection occurs in a critically stressed rock, hydrogen injection and withdrawal in saline aquifers could result in more incidence of microseismicity compared to hydrogen storage in depleted fields or even gas storage in depleted fields. This study quantifies uncertainties in data and pinpoints areas where petrophysical measurements could minimize the uncertainty associated with critical parameters relevant to underground hydrogen storage. It also identifies gaps in measurements for hydrogen storage in porous media. These parameters with large uncertainty are crucial for selecting optimal sites for hydrogen storage and detecting subsurface integrity issues when monitoring for underground hydrogen storage in porous media.
{"title":"Underground Hydrogen Storage in Porous Media: The Potential Role of Petrophysics","authors":"E. Okoroafor, Lokesh Kumar Sekar, Henry Galvis","doi":"10.30632/pjv65n3-2024a3","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a3","url":null,"abstract":"The objective of this study is to showcase the key geological and reservoir engineering parameters that influence underground hydrogen storage, demonstrate the value of some petrophysical data, and show how hydrogen storage differs between depleted gas fields and saline aquifers for reservoir and geomechanical modeling. We utilized numerical simulation modeling to create a base-case model of a synthetic reservoir that accurately represented the hydrodynamic conditions relevant to underground hydrogen storage in porous media. A two-step sensitivity analysis was then conducted. Firstly, we identified the critical parameters that significantly influence the storage and flow of hydrogen in porous media. Subsequently, we analyzed the geomechanical impact of underground hydrogen storage. In addition, we compared the behavior of hydrogen storage to natural gas storage. The study showed that the reservoir depth or current pressure, the reservoir dip, and the flow capacity were the top three factors impacting the optimal withdrawal of hydrogen. The study also revealed that rock displacement and stress changes were important to be monitored, while changes in strain were not significant. If it is assumed that injection occurs in a critically stressed rock, hydrogen injection and withdrawal in saline aquifers could result in more incidence of microseismicity compared to hydrogen storage in depleted fields or even gas storage in depleted fields. This study quantifies uncertainties in data and pinpoints areas where petrophysical measurements could minimize the uncertainty associated with critical parameters relevant to underground hydrogen storage. It also identifies gaps in measurements for hydrogen storage in porous media. These parameters with large uncertainty are crucial for selecting optimal sites for hydrogen storage and detecting subsurface integrity issues when monitoring for underground hydrogen storage in porous media.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"63 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141408731","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}
Stacey Althaus, JinHong Chen, Qiushi Sun, J. D. Broyles
Two-dimensional (2D) T1-T2 NMR has been widely proposed as a method to determine the fluids present in unconventional source rocks. However, the assignment of the components in the 2D T1- T2 NMR spectra has so far been based on conceptual consideration and lacks rigorous experimental verification. Many assignment variations appeared in the literature and can be misleading. For example, large T1/T2 peaks in the 2D T1-T2 NMR were suggested to be fluid in small pores coupled with kerogen solid through dipolar relaxation. Our recent 500-MHz NMR relaxation experiments found that the dipolar relaxation between nanoconfined fluids and solid matrix is not big enough to support that large T1/T2 interpretation. The objective of this paper is to determine what quantitative data can be obtained using 2D T1-T2 NMR from source rocks with high confidence. We found the oil and water saturation can be accurately measured in preserved source rock plugs. Two-dimensional T1-T2 NMR data were collected on preserved core plugs from five wells of a source rock reservoir using an inversion-recovery Carr-Purcell-Meiboom-Gill (CMPG) pulse sequence on a 12-MHz NMR instrument. The acquired 2D data were inverted using an optimized inversion software, MUPen2D. We then obtain oil and water content in the plug from the 2D T1-T2 NMR using an in-house-developed NMR MATLAB app. The porosity of all the plugs was measured using a combined NMR and gas porosimetry (CNG) method. Oil and water saturation were also obtained using an industry-standard method developed by the Gas Research Institute (GRI) on the rock material close to where the plug was drilled. The oil and water saturations measured on the preserved plugs using 2D T1-T2 NMR and CNG are consistent with those from the GRI method using crushed rocks and an invasive cleaning procedure. The results show that oil and water saturations were accurately determined from 2D T1-T2 NMR on preserved source rock samples with high confidence. The NMR method is nondestructive and noninvasive and takes less than 4 hours on a preserved source rock plug, while GRI is destructive and invasive and can take several weeks for an accurate measurement on one sample. The measured results can be further used to determine the production potential of a source rock well in combination with log data.
{"title":"Determine Oil and Water Saturations in Preserved Source Rocks From 2D T1-T2 NMR","authors":"Stacey Althaus, JinHong Chen, Qiushi Sun, J. D. Broyles","doi":"10.30632/pjv65n3-2024a6","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a6","url":null,"abstract":"Two-dimensional (2D) T1-T2 NMR has been widely proposed as a method to determine the fluids present in unconventional source rocks. However, the assignment of the components in the 2D T1- T2 NMR spectra has so far been based on conceptual consideration and lacks rigorous experimental verification. Many assignment variations appeared in the literature and can be misleading. For example, large T1/T2 peaks in the 2D T1-T2 NMR were suggested to be fluid in small pores coupled with kerogen solid through dipolar relaxation. Our recent 500-MHz NMR relaxation experiments found that the dipolar relaxation between nanoconfined fluids and solid matrix is not big enough to support that large T1/T2 interpretation. The objective of this paper is to determine what quantitative data can be obtained using 2D T1-T2 NMR from source rocks with high confidence. We found the oil and water saturation can be accurately measured in preserved source rock plugs. Two-dimensional T1-T2 NMR data were collected on preserved core plugs from five wells of a source rock reservoir using an inversion-recovery Carr-Purcell-Meiboom-Gill (CMPG) pulse sequence on a 12-MHz NMR instrument. The acquired 2D data were inverted using an optimized inversion software, MUPen2D. We then obtain oil and water content in the plug from the 2D T1-T2 NMR using an in-house-developed NMR MATLAB app. The porosity of all the plugs was measured using a combined NMR and gas porosimetry (CNG) method. Oil and water saturation were also obtained using an industry-standard method developed by the Gas Research Institute (GRI) on the rock material close to where the plug was drilled. The oil and water saturations measured on the preserved plugs using 2D T1-T2 NMR and CNG are consistent with those from the GRI method using crushed rocks and an invasive cleaning procedure. The results show that oil and water saturations were accurately determined from 2D T1-T2 NMR on preserved source rock samples with high confidence. The NMR method is nondestructive and noninvasive and takes less than 4 hours on a preserved source rock plug, while GRI is destructive and invasive and can take several weeks for an accurate measurement on one sample. The measured results can be further used to determine the production potential of a source rock well in combination with log data.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"59 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141412803","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 Oman Drilling Project was conducted as a part of the International Continental Scientific Drilling Program (ICDP) from 2017 to 2018, and several boreholes, including four across the crust-mantle transition zone, were drilled in the program (Matter et al., 2019; Kelemen et al., 2020; Takazawa, 2021). A full suite of slim and conventional wireline logs, as well as high-resolution electrical borehole image and geochemical spectroscopy logs (Ellis and Singer, 2007; Liu, 2017), were acquired near the coring borehole. Full core samples were acquired from the coring boreholes, and various core analyses were conducted manually with significant time and effort to create a detailed core description. Identification of geological facies is crucial to understanding the complicated crust-mantle transition zone. Being able to achieve this facies recognition from available logging data using an automated method would optimize the operation cost and analysis time. This would be useful for the future scientific ultradeep ocean drilling Mohole to Mantle (M2M) project (Umino, 2015; Moe et al., 2018) planned by the International Ocean Discovery Program (IODP). We propose an automatic geological facies analysis (FaciesSpect) method using borehole images and other petrophysical log data on the Oman Drilling Project. Among the available logging data, borehole image (resistivity type with dynamic color scaling) and two log curves (Fe and Ca) from geochemical spectroscopy log data were selected for the automatic facies analysis. Fifteen clusters were classified from the selected log data using the proposed approach. The cluster distribution trend was consistent with cuttings and core lithologies and indicated three major lithology zones: dunite, gabbro, and harzburgite. Two automatic facies analysis methods, class-based machine learning and heterogeneous rock analysis, were performed to compare the results with those of FaciesSpect. These are well-established methods that can validate the newer FaciesSpect method result. The class results of the three different methods were compared. They are matched at major lithology change boundaries. FaciesSpect class results calibrated by core data could be matched not only with core lithology changes but also with texture changes, such as massive, layered, severely altered, deformed, and fractured, due to the advantage of using borehole image data as one form of input. In this case study, we applied the automatic facies analysis to a complicated scientific drilling well in the crust-mantle transition zone for the first time. The result successfully identified different lithologies, such as dunite and harzburgite, which have a high potential for hydrogen generation and are important resources for emissions-free renewable energy. We validated that the FaciesSpect method is useful for rapidly understanding the overall lithology and texture trends such as fractured, deformed, and massive intervals. The FaciesSpect method can also sa
{"title":"Automatic Geological Facies Analysis in Crust-Mantle Transition Zone","authors":"Chiaki Morelli, Shiduo Yang, Yuki Maehara, Huimin Cai, Kyaw Moe, Yasuhiro Yamada, Juerg Matter","doi":"10.30632/pjv65n3-2024a4","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a4","url":null,"abstract":"The Oman Drilling Project was conducted as a part of the International Continental Scientific Drilling Program (ICDP) from 2017 to 2018, and several boreholes, including four across the crust-mantle transition zone, were drilled in the program (Matter et al., 2019; Kelemen et al., 2020; Takazawa, 2021). A full suite of slim and conventional wireline logs, as well as high-resolution electrical borehole image and geochemical spectroscopy logs (Ellis and Singer, 2007; Liu, 2017), were acquired near the coring borehole. Full core samples were acquired from the coring boreholes, and various core analyses were conducted manually with significant time and effort to create a detailed core description. Identification of geological facies is crucial to understanding the complicated crust-mantle transition zone. Being able to achieve this facies recognition from available logging data using an automated method would optimize the operation cost and analysis time. This would be useful for the future scientific ultradeep ocean drilling Mohole to Mantle (M2M) project (Umino, 2015; Moe et al., 2018) planned by the International Ocean Discovery Program (IODP). We propose an automatic geological facies analysis (FaciesSpect) method using borehole images and other petrophysical log data on the Oman Drilling Project. Among the available logging data, borehole image (resistivity type with dynamic color scaling) and two log curves (Fe and Ca) from geochemical spectroscopy log data were selected for the automatic facies analysis. Fifteen clusters were classified from the selected log data using the proposed approach. The cluster distribution trend was consistent with cuttings and core lithologies and indicated three major lithology zones: dunite, gabbro, and harzburgite. Two automatic facies analysis methods, class-based machine learning and heterogeneous rock analysis, were performed to compare the results with those of FaciesSpect. These are well-established methods that can validate the newer FaciesSpect method result. The class results of the three different methods were compared. They are matched at major lithology change boundaries. FaciesSpect class results calibrated by core data could be matched not only with core lithology changes but also with texture changes, such as massive, layered, severely altered, deformed, and fractured, due to the advantage of using borehole image data as one form of input. In this case study, we applied the automatic facies analysis to a complicated scientific drilling well in the crust-mantle transition zone for the first time. The result successfully identified different lithologies, such as dunite and harzburgite, which have a high potential for hydrogen generation and are important resources for emissions-free renewable energy. We validated that the FaciesSpect method is useful for rapidly understanding the overall lithology and texture trends such as fractured, deformed, and massive intervals. The FaciesSpect method can also sa","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"1993 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141400890","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 examines the potential of nuclear logging techniques, ubiquitous in the petroleum industry, to extract geological information needed to support the transition to the low-carbon energy future being envisioned to replace fossil fuels and explores the technological advances needed. Assessment to date, using Monte Carlo modeling and available measurements shows promise in (1) monitoring injected CO2 for carbon capture and sequestration (CCS) to mitigate climate change, (2) assessing sites to bury high-level waste to support nuclear power generation and later monitor buried radioactive waste, and (3) in geothermal, a renewable option. For each case, standard techniques, while promising, also show technological gaps. Additionally, two postulated low-carbon areas supporting renewable energy generation are briefly examined—downhole quantification of strategic minerals and prediction and detection of naturally occurring hydrogen in the geology. Three related technology areas are also examined: transition from the current dual-track philosophy of nuclear logging tool design to a compact, more universally applicable advanced accelerator-based multiple-parameter tool concept, incorporation of artificial intelligence-guided physical health management systems to minimize generator failure, and advances in generation/detection hardware and software. Software advances would include codes with dynamic visualization and improved nuclear data libraries to design, calibrate, and assess tools, especially to provide a priori space-time profiles of attendant multiple radiation types, which would arise in the novel systems being postulated. Two exotic concepts, recently suggested also for downhole use, associate-particle imaging to monitor casing integrity of wells storing methane and hydrogen and muon-based deep density probing, are briefly explored.
{"title":"Nuclear Logging in Geological Probing for a Low-Carbon Energy Future – A New Frontier?","authors":"Ahmed Badruzzaman","doi":"10.30632/pjv65n3-2024a1","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a1","url":null,"abstract":"This paper examines the potential of nuclear logging techniques, ubiquitous in the petroleum industry, to extract geological information needed to support the transition to the low-carbon energy future being envisioned to replace fossil fuels and explores the technological advances needed. Assessment to date, using Monte Carlo modeling and available measurements shows promise in (1) monitoring injected CO2 for carbon capture and sequestration (CCS) to mitigate climate change, (2) assessing sites to bury high-level waste to support nuclear power generation and later monitor buried radioactive waste, and (3) in geothermal, a renewable option. For each case, standard techniques, while promising, also show technological gaps. Additionally, two postulated low-carbon areas supporting renewable energy generation are briefly examined—downhole quantification of strategic minerals and prediction and detection of naturally occurring hydrogen in the geology. Three related technology areas are also examined: transition from the current dual-track philosophy of nuclear logging tool design to a compact, more universally applicable advanced accelerator-based multiple-parameter tool concept, incorporation of artificial intelligence-guided physical health management systems to minimize generator failure, and advances in generation/detection hardware and software. Software advances would include codes with dynamic visualization and improved nuclear data libraries to design, calibrate, and assess tools, especially to provide a priori space-time profiles of attendant multiple radiation types, which would arise in the novel systems being postulated. Two exotic concepts, recently suggested also for downhole use, associate-particle imaging to monitor casing integrity of wells storing methane and hydrogen and muon-based deep density probing, are briefly explored.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141406012","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 Bundesgesellschaft für Endlagerung mbH (BGE; “Federal Company for Radioactive Waste Disposal”) is responsible for identifying a repository site in Germany for the storage of high-level radioactive waste, ensuring the best possible safety for at least 1 million years (StandAG, 2017). The three-phase site selection process is currently in Step 2 of its Phase I. Around 90 potentially suitable sub-areas are evaluated via individual representative preliminary safety assessments. These sub-areas cover all types of potential containment rock: allochthonous and autochthonous rock salt, claystone, and crystalline rock. Such a comprehensive assessment is challenging for a host rock that covers vast areas like claystone or autochthonous salt. One of the steps towards estimating parameters for a site search process requires the analysis of numerous logs from the areas of interest and their vicinity. Unfortunately, computing these parameters is a much more complex problem than it seems. While gamma ray logs have been the petrophysicist’s workhorse for decades, they allow no quantification of clay properties. Nuclear magnetic resonance and neutron activation logs yield critical information but are scarce in old wells. Decades of research have given good algorithms for defining wet clay porosity from resistivity logs, but inverting those for porosity and tortuosity remains challenging. Another log-derived parameter is a formation’s homogeneity, which quantifies the jaggedness of a logging curve. A vertical variogram or variable filter technique can accomplish this.
Bundesgesellschaft für Endlagerung mbH（BGE；"联邦放射性废物处置公司"）负责在德国确定一个用于贮存高放射性废物的贮存场址，以确保至少 100 万年的最佳安全性（StandAG，2017 年）。约 90 个潜在合适的子区域已通过具有代表性的单个初步安全评估进行了评估。这些子区域涵盖了所有类型的潜在安全壳岩石：同生和自生岩盐、粘土岩和结晶岩。对于像粘土岩或自生岩盐这样覆盖面积广阔的围岩来说，进行这样的全面评估具有挑战性。为估算矿址搜索过程中的参数，其中一个步骤需要对感兴趣区域及其附近的大量测井资料进行分析。遗憾的是，计算这些参数是一个比想象中复杂得多的问题。虽然伽马射线测井几十年来一直是岩石物理学家的工作工具，但它们无法量化粘土的特性。核磁共振和中子活化测井可提供关键信息，但在老井中却很少见。数十年的研究已经给出了从电阻率测井曲线中定义湿粘土孔隙度的良好算法，但将这些算法反演为孔隙度和曲折度仍然具有挑战性。另一个测井参数是地层的均质性，即测井曲线的锯齿度。垂直变异图或可变滤波技术可以实现这一目的。
{"title":"Petrophysical Analyses for Supporting the Search for a Claystone-Hosted Nuclear Repository","authors":"Joachim Strobel","doi":"10.30632/pjv65n3-2024a2","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a2","url":null,"abstract":"The Bundesgesellschaft für Endlagerung mbH (BGE; “Federal Company for Radioactive Waste Disposal”) is responsible for identifying a repository site in Germany for the storage of high-level radioactive waste, ensuring the best possible safety for at least 1 million years (StandAG, 2017). The three-phase site selection process is currently in Step 2 of its Phase I. Around 90 potentially suitable sub-areas are evaluated via individual representative preliminary safety assessments. These sub-areas cover all types of potential containment rock: allochthonous and autochthonous rock salt, claystone, and crystalline rock. Such a comprehensive assessment is challenging for a host rock that covers vast areas like claystone or autochthonous salt. One of the steps towards estimating parameters for a site search process requires the analysis of numerous logs from the areas of interest and their vicinity. Unfortunately, computing these parameters is a much more complex problem than it seems. While gamma ray logs have been the petrophysicist’s workhorse for decades, they allow no quantification of clay properties. Nuclear magnetic resonance and neutron activation logs yield critical information but are scarce in old wells. Decades of research have given good algorithms for defining wet clay porosity from resistivity logs, but inverting those for porosity and tortuosity remains challenging. Another log-derived parameter is a formation’s homogeneity, which quantifies the jaggedness of a logging curve. A vertical variogram or variable filter technique can accomplish this.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"87 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141402662","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 rock formations in oil and gas reservoirs are predominantly composed of laminated shale, which contains various defects such as pores and fractures. These defects have a significant impact on the stability of wellbore walls. As a result, this study utilized rock samples from a specific oil and gas reservoir and introduced pre-existing pore and fracture defects within them. Uniaxial compression tests were conducted on rock specimens with varying angles between the fractures and the bedding planes. The study involved measuring and analyzing the impact of pre-existing defect morphology on shale’s mechanical properties. Additionally, through the use of digital image correlation (DIC) technology, a comprehensive strain field map was obtained, depicting the initiation, propagation, and ultimate failure of surface cracks in shale under loading conditions. This allowed for both qualitative and quantitative analysis of the connection between shale’s damage and failure processes and the evolution of strain fields. Ultimately, this research provides a theoretical basis for wellbore stability and the development of shale oil and gas fields. Conclusions drawn from the study are as follows. With an increase in fracture angle, the rock’s elastic modulus gradually increases, and both compressive strength and strain exhibit a pattern of higher values on both ends and lower values in the middle. When the fracture angle is less than 30°, significant stress concentration occurs at the tip of the fracture. When the angle exceeds 60°, stress concentration around pores dominates. In the range of 30° to 60°, there is a combined stress concentration around both pores and fractures, significantly reducing rock stability. Crack propagation is influenced by bedding planes and exhibits varying degrees of ductility, ultimately resulting in a tension-shear mixed failure. When fractures are parallel to bedding planes (angle = 0°), defects are symmetrically distributed, and stress concentration at the fracture tip dominates, leading to crack initiation from the fracture tip and eventually forming an “H”-shaped tensile failure. When fractures are perpendicular to bedding planes (angle = 90°), stress concentration around pores is greater than at the fracture tip, causing cracks to initiate around pores and eventually collapsing on one side of the fracture.
{"title":"Study on the Damage and Failure Process of Prefabricated Hole-Fracture Combination Defects in Shale","authors":"Han Jiang, Zhan Qu, Weihang Liu","doi":"10.30632/pjv65n3-2024a7","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a7","url":null,"abstract":"The rock formations in oil and gas reservoirs are predominantly composed of laminated shale, which contains various defects such as pores and fractures. These defects have a significant impact on the stability of wellbore walls. As a result, this study utilized rock samples from a specific oil and gas reservoir and introduced pre-existing pore and fracture defects within them. Uniaxial compression tests were conducted on rock specimens with varying angles between the fractures and the bedding planes. The study involved measuring and analyzing the impact of pre-existing defect morphology on shale’s mechanical properties. Additionally, through the use of digital image correlation (DIC) technology, a comprehensive strain field map was obtained, depicting the initiation, propagation, and ultimate failure of surface cracks in shale under loading conditions. This allowed for both qualitative and quantitative analysis of the connection between shale’s damage and failure processes and the evolution of strain fields. Ultimately, this research provides a theoretical basis for wellbore stability and the development of shale oil and gas fields. Conclusions drawn from the study are as follows. With an increase in fracture angle, the rock’s elastic modulus gradually increases, and both compressive strength and strain exhibit a pattern of higher values on both ends and lower values in the middle. When the fracture angle is less than 30°, significant stress concentration occurs at the tip of the fracture. When the angle exceeds 60°, stress concentration around pores dominates. In the range of 30° to 60°, there is a combined stress concentration around both pores and fractures, significantly reducing rock stability. Crack propagation is influenced by bedding planes and exhibits varying degrees of ductility, ultimately resulting in a tension-shear mixed failure. When fractures are parallel to bedding planes (angle = 0°), defects are symmetrically distributed, and stress concentration at the fracture tip dominates, leading to crack initiation from the fracture tip and eventually forming an “H”-shaped tensile failure. When fractures are perpendicular to bedding planes (angle = 90°), stress concentration around pores is greater than at the fracture tip, causing cracks to initiate around pores and eventually collapsing on one side of the fracture.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"18 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141411530","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}
Guanghui Duan, Zhiqi Zhong, Meiyan Fu, Jiacheng Xu, Ya Deng, Can Ling, Keran Li
Reservoir characterization in carbonate formations plays a crucial role in understanding the complex pore structures and permeability properties. While absolute pore-throat radius (APTR) and R35 have been widely accepted in pore-scale rock typing, they fall short of providing detailed pore-throat distribution (PTD) information. To address this limitation and enhance PTD indication during rock classification, we introduce a novel approach—the R35 and fractal joint rock typing method—incorporating a new parameter, Dn (fractal dimension). This method is developed based on the analysis of mercury injection capillary pressure (MICP) data obtained from 20 carbonate samples in the Middle East, specifically Iraq. We delve into the discussion of APTR and R35 methods, employing both PTD and thin-section images to gain comprehensive insights into rock typing. Our approach incorporates a whole curve fractal-based model to determine the fractal dimension, Dn. The analysis reveals that Dn in each R35 rock type exhibits a decreasing trend with higher Hg intrusion peaks and wider pore-throat radius, providing valuable information on the distribution of pores within the rock samples. Furthermore, we extend our analysis to include the surface fractal dimension, Ds, obtained through two-dimensional (2D) fractal analysis on typical pores in binary thin-section images. The consistent decreasing trend of Dn aligns with the findings from Ds analysis, underscoring the effectiveness of parameter Dn in capturing the intricate pore structures within carbonate formations. Our results suggest that parameter Dn has the potential to serve as a standalone criterion in rock typing, eliminating the need for pretyping by R35 or APTR. The versatility of Dn as an indicator of pore distribution and complexity underscores its significance in advancing our understanding of carbonate reservoirs. As a recommendation, further exploration through additional fractal-based analyses is encouraged to solidify the role of parameter Dn in becoming a pivotal factor in the evolving field of rock typing.
{"title":"A New R35 and Fractal Joint Rock Typing Method Using MICP Analysis: A Case Study in Middle East Iraq","authors":"Guanghui Duan, Zhiqi Zhong, Meiyan Fu, Jiacheng Xu, Ya Deng, Can Ling, Keran Li","doi":"10.30632/pjv65n3-2024a8","DOIUrl":"https://doi.org/10.30632/pjv65n3-2024a8","url":null,"abstract":"Reservoir characterization in carbonate formations plays a crucial role in understanding the complex pore structures and permeability properties. While absolute pore-throat radius (APTR) and R35 have been widely accepted in pore-scale rock typing, they fall short of providing detailed pore-throat distribution (PTD) information. To address this limitation and enhance PTD indication during rock classification, we introduce a novel approach—the R35 and fractal joint rock typing method—incorporating a new parameter, Dn (fractal dimension). This method is developed based on the analysis of mercury injection capillary pressure (MICP) data obtained from 20 carbonate samples in the Middle East, specifically Iraq. We delve into the discussion of APTR and R35 methods, employing both PTD and thin-section images to gain comprehensive insights into rock typing. Our approach incorporates a whole curve fractal-based model to determine the fractal dimension, Dn. The analysis reveals that Dn in each R35 rock type exhibits a decreasing trend with higher Hg intrusion peaks and wider pore-throat radius, providing valuable information on the distribution of pores within the rock samples. Furthermore, we extend our analysis to include the surface fractal dimension, Ds, obtained through two-dimensional (2D) fractal analysis on typical pores in binary thin-section images. The consistent decreasing trend of Dn aligns with the findings from Ds analysis, underscoring the effectiveness of parameter Dn in capturing the intricate pore structures within carbonate formations. Our results suggest that parameter Dn has the potential to serve as a standalone criterion in rock typing, eliminating the need for pretyping by R35 or APTR. The versatility of Dn as an indicator of pore distribution and complexity underscores its significance in advancing our understanding of carbonate reservoirs. As a recommendation, further exploration through additional fractal-based analyses is encouraged to solidify the role of parameter Dn in becoming a pivotal factor in the evolving field of rock typing.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"78 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141405668","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}
Chicheng Xu, Lei Fu, Tao Lin, Weichang Li, Yaser Alzayer, Zainab Al Ibrahim
Depth matching or depth shifting between well logs acquired from different runs or between core scans and well logs is a critical data quality control task to ensure subsequent accurate petrophysical interpretation and modeling. Conventional depth-shifting workflow heavily relies on human expertise to manually match a series of peaks and troughs between log curves, which is often subjective, error-prone, and cumbersome. Therefore, it is necessary to establish an automatic depth-shifting workflow to perform this routine yet important task accurately in a consistent and efficient manner. We implemented an automatic workflow to emulate human expertise to identify important “events” such as peaks, troughs, and bed boundaries on log curves and then intelligently match the identified series of events between log curves with local maximum correlation criteria to generate a depth shift table. We applied the automatic workflow in a field case to shift the well log and core gamma ray and delivered a depth shift table comparable to manual depth matching. The final shifted log achieved a significantly enhanced correlation with the reference log. The events identifying and matching method presents a white-box solution that still follows the conventional petrophysical wisdom and allows more user interaction to fine-tune the results. The users have full control of the parameters for optimal results.
{"title":"Automatic Depth Shifting by Identifying and Matching Events on Well Logs Chicheng Xu","authors":"Chicheng Xu, Lei Fu, Tao Lin, Weichang Li, Yaser Alzayer, Zainab Al Ibrahim","doi":"10.30632/pjv65n2-2024a7","DOIUrl":"https://doi.org/10.30632/pjv65n2-2024a7","url":null,"abstract":"Depth matching or depth shifting between well logs acquired from different runs or between core scans and well logs is a critical data quality control task to ensure subsequent accurate petrophysical interpretation and modeling. Conventional depth-shifting workflow heavily relies on human expertise to manually match a series of peaks and troughs between log curves, which is often subjective, error-prone, and cumbersome. Therefore, it is necessary to establish an automatic depth-shifting workflow to perform this routine yet important task accurately in a consistent and efficient manner. We implemented an automatic workflow to emulate human expertise to identify important “events” such as peaks, troughs, and bed boundaries on log curves and then intelligently match the identified series of events between log curves with local maximum correlation criteria to generate a depth shift table. We applied the automatic workflow in a field case to shift the well log and core gamma ray and delivered a depth shift table comparable to manual depth matching. The final shifted log achieved a significantly enhanced correlation with the reference log. The events identifying and matching method presents a white-box solution that still follows the conventional petrophysical wisdom and allows more user interaction to fine-tune the results. The users have full control of the parameters for optimal results.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"227 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140777258","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}
Abraham Grader, Knut Arne Birkedal, Robert Engelman, Kristoffer Birkeland, N. Aarseth
The Valhall chalk field has produced more than 1 billion barrels of oil equivalents over the last 40 years, primarily from the homogeneous Tor Formation. The underlying Hod Formation is more heterogeneous and is less maturely developed. The extent of heterogeneity poses a challenge in the evaluation of multiphase fluid flow properties. The objective of the work was to use digital core analysis to generate early relative permeability data to leverage and compare with conventional physical steady-state relative permeability data. Accurate digital and physical description of capillary pressure and relative permeability in the high-porosity chalk is complicated by both low permeabilities and heterogeneity. The main challenge with chalk is that flow occurs in a nano-environment. Physically, the nano-environment translates to low permeability, difficult rock preparation, and extensive experimental time, especiallyfor steady-state flow experiments. Representative three-dimensional (3D) digital rocks were generated using a combination of X-ray computed tomography (CT) and focused ion beam-scanning electron microscopy (FIB-SEM) methods. The digital rocks were used to simulate two-phase flow and generate relative permeabilities and sensitivity to wettability. Physical steady-state and digital relative permeabilities on several core plugs and subsets are compared in this study, which discusses the advantages of performing both as part of the formation evaluation process. The physical and digital results compare reasonably well. The physical results provide a relative permeability anchor, and the digital results provide the leverage of early results, parametric sensitivities, and quality assurance. Hence, integration between digital and physical core analysis yields a robust understanding and input for uncertainty modeling.
在过去的 40 年里，瓦尔霍尔白垩油田主要从均质的 Tor Formation（托尔地层）生产了超过 10 亿桶石油当量。下层霍德地层的异质性更强，开发得也不太成熟。异质性的程度给多相流体流动特性的评估带来了挑战。这项工作的目的是利用数字岩心分析生成早期相对渗透率数据，以便与传统的物理稳态相对渗透率数据进行比较。由于低渗透率和异质性，在高孔隙度白垩层中对毛细管压力和相对渗透率进行精确的数字和物理描述变得十分复杂。白垩的主要挑战在于流动发生在纳米环境中。从物理上讲，纳米环境意味着渗透率低、岩石制备困难、实验时间长，尤其是稳态流动实验。采用 X 射线计算机断层扫描（CT）和聚焦离子束扫描电子显微镜（FIB-SEM）相结合的方法生成了具有代表性的三维（3D）数字岩石。数字岩石用于模拟两相流，并生成相对渗透率和对润湿性的敏感性。本研究对几个岩心堵塞和子集的物理稳态渗透率和数字相对渗透率进行了比较，讨论了在地层评价过程中进行这两种方法的优点。物理和数字结果比较合理。物理结果提供了一个相对渗透率锚，而数字结果提供了早期结果、参数敏感性和质量保证的杠杆作用。因此，数字岩心分析与物理岩心分析相结合，可以为不确定性建模提供可靠的理解和输入。
{"title":"Integrated Physical and Digital Chalk Relative Permeability Evaluation: A Case Study","authors":"Abraham Grader, Knut Arne Birkedal, Robert Engelman, Kristoffer Birkeland, N. Aarseth","doi":"10.30632/pjv65n2-2024a1","DOIUrl":"https://doi.org/10.30632/pjv65n2-2024a1","url":null,"abstract":"The Valhall chalk field has produced more than 1 billion barrels of oil equivalents over the last 40 years, primarily from the homogeneous Tor Formation. The underlying Hod Formation is more heterogeneous and is less maturely developed. The extent of heterogeneity poses a challenge in the evaluation of multiphase fluid flow properties. The objective of the work was to use digital core analysis to generate early relative permeability data to leverage and compare with conventional physical steady-state relative permeability data. Accurate digital and physical description of capillary pressure and relative permeability in the high-porosity chalk is complicated by both low permeabilities and heterogeneity. The main challenge with chalk is that flow occurs in a nano-environment. Physically, the nano-environment translates to low permeability, difficult rock preparation, and extensive experimental time, especiallyfor steady-state flow experiments. Representative three-dimensional (3D) digital rocks were generated using a combination of X-ray computed tomography (CT) and focused ion beam-scanning electron microscopy (FIB-SEM) methods. The digital rocks were used to simulate two-phase flow and generate relative permeabilities and sensitivity to wettability. Physical steady-state and digital relative permeabilities on several core plugs and subsets are compared in this study, which discusses the advantages of performing both as part of the formation evaluation process. The physical and digital results compare reasonably well. The physical results provide a relative permeability anchor, and the digital results provide the leverage of early results, parametric sensitivities, and quality assurance. Hence, integration between digital and physical core analysis yields a robust understanding and input for uncertainty modeling.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"62 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140784095","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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