Carbon capture, utilization, and storage (CCUS) is a process that involves capturing carbon dioxide (CO2) emissions and storing them in geological formations. While the challenge of CCUS is one of multiple disciplines, this paper will discuss the key petrophysical considerations worth noting for CCUS projects. As the storage capacity and effectiveness of the storage reservoir depend on the physical and chemical properties of the geological formations that are used for storage, petrophysicists working on CCUS projects must have a good understanding of the subsurface and its limitations. Any CCUS project can be better managed by application and adherence to the CO2 Storage Resources Management System (SRMS), which aims to develop a consistent approach to estimating storable quantities of CO2 in the subsurface and evaluating development projects. In this paper, we will also discuss a risk matrix that we have designed as a tool for project petrophysicists to document uncertainties and rank them to enhance communication with team members. We finally share a petrophysical checklist to highlight considerations as the evaluation of prospective, contingent, and (commercial storage) capacity-scale CCUS projects are matured and use a well in the North West Shelf, Australia, as a case study to show how reservoirs can be analyzed for suitability for CO2 storage.
{"title":"Petrophysical Considerations for CO2 Capture and Storage","authors":"Munish Kumar, Gabriel Lauderdale-Smith","doi":"10.30632/pjv65n1-2024a3","DOIUrl":"https://doi.org/10.30632/pjv65n1-2024a3","url":null,"abstract":"Carbon capture, utilization, and storage (CCUS) is a process that involves capturing carbon dioxide (CO2) emissions and storing them in geological formations. While the challenge of CCUS is one of multiple disciplines, this paper will discuss the key petrophysical considerations worth noting for CCUS projects. As the storage capacity and effectiveness of the storage reservoir depend on the physical and chemical properties of the geological formations that are used for storage, petrophysicists working on CCUS projects must have a good understanding of the subsurface and its limitations. Any CCUS project can be better managed by application and adherence to the CO2 Storage Resources Management System (SRMS), which aims to develop a consistent approach to estimating storable quantities of CO2 in the subsurface and evaluating development projects. In this paper, we will also discuss a risk matrix that we have designed as a tool for project petrophysicists to document uncertainties and rank them to enhance communication with team members. We finally share a petrophysical checklist to highlight considerations as the evaluation of prospective, contingent, and (commercial storage) capacity-scale CCUS projects are matured and use a well in the North West Shelf, Australia, as a case study to show how reservoirs can be analyzed for suitability for CO2 storage.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"40 24","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139685658","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 is to update the information provided in the author’s previous papers on evaluating the uncertainty in least squares results. It is prompted by new information that shows that the usefulness of any least squares result cannot be guaranteed by conventional statistics (such as R-squared, F-statistic, or standard error of the regression, sigma). A new method based on the singular value decomposition (SVD) of a matrix, when accompanied by a Relative Error Bound (REB) on the estimated parameters, provides the user with a tool that can better assess the usefulness of any least squares result. Another important aspect of the REB is that it provides the user of the SVD method with a powerful tool for judging which is the best among several candidate solutions. In addition, it provides the user with a numerically stable method of computing the data ordinarily provided by principal component regression by eliminating the need to perform an eigenvector-eigenvalue analysis of an ATA matrix. This is of particular interest because forming the ATA matrix is often accompanied by a loss of data. The new method also provides the user with an improved method for selection of which principal components should be retained for a given problem.
本文旨在更新作者以前关于评估最小二乘法结果不确定性的论文中提供的信息。新信息表明，任何最小二乘法结果的有用性都无法通过常规统计（如 R 方、F 统计或回归标准误差 sigma）来保证。一种基于矩阵奇异值分解（SVD）的新方法，配合估计参数的相对误差约束（REB），为用户提供了一种可以更好地评估任何最小二乘法结果有用性的工具。REB 的另一个重要方面是，它为 SVD 方法的用户提供了一个强大的工具，用于判断几个候选方案中哪个是最佳方案。此外，由于无需对 ATA 矩阵进行特征向量-特征值分析，它还为用户提供了一种数值稳定的方法，用于计算主成分回归通常提供的数据。这一点尤为重要，因为形成 ATA 矩阵往往会导致数据丢失。新方法还为用户提供了一种改进的方法，用于选择在特定问题中应保留哪些主成分。
{"title":"Evaluating the Usefulness of Least Squares Regression in Petrophysics Interpretation","authors":"Lee Etnyre","doi":"10.30632/pjv65n1-2024a4","DOIUrl":"https://doi.org/10.30632/pjv65n1-2024a4","url":null,"abstract":"This paper is to update the information provided in the author’s previous papers on evaluating the uncertainty in least squares results. It is prompted by new information that shows that the usefulness of any least squares result cannot be guaranteed by conventional statistics (such as R-squared, F-statistic, or standard error of the regression, sigma). A new method based on the singular value decomposition (SVD) of a matrix, when accompanied by a Relative Error Bound (REB) on the estimated parameters, provides the user with a tool that can better assess the usefulness of any least squares result. Another important aspect of the REB is that it provides the user of the SVD method with a powerful tool for judging which is the best among several candidate solutions. In addition, it provides the user with a numerically stable method of computing the data ordinarily provided by principal component regression by eliminating the need to perform an eigenvector-eigenvalue analysis of an ATA matrix. This is of particular interest because forming the ATA matrix is often accompanied by a loss of data. The new method also provides the user with an improved method for selection of which principal components should be retained for a given problem.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"6 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139883040","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 Waxman-Smits formula was introduced in 1968 as a parallel conductance model to improve previous models. A careful inspection of the Waxman and Smits model reveals it is not a parallel conduction model by the conventional definition. First, Waxman-Smits assumed that “the electrical current transported by the counterions associated with the clay travels along the same tortuous path as the current attributed to the ions in the pore water” (Waxman and Smits, 1968), removing an essential feature of a parallel conduction model, that there be two separate conductors. Based on this assumption, they assign the same geometrical factor to both current paths. The geometrical factor is defined as the reciprocal of the formation resistivity factor (1/F or σm). Waxman-Smits found experimentally that a shaly sand appeared to have an F that was larger than a clean sand and introduced F* to account for this. Therefore, the tortuosity of the current paths through the clay and the pore water were deemed to be equivalent, with both tortuosities increasing equally as the clay content increased. Second, a parallel model requires the bulk conductivity of a volume to be weighted by the fractional volumes of the separate clay and interstitial water current paths. Clavier et al. (1977) discovered during the field testing of the new 1.1-GHz electromagnetic propagation tool that there existed a volume of clay water of near-constant salinity in shales. These two concepts are not accounted for in the Waxman-Smits model. A re-evaluation of the Waxman-Smits database by Clavier et al. (1977, 1984) revealed the F* increase was primarily due to the Waxman-Smits model not accounting for the physical presence of the volume of the clay water. The inclusion of the clay water volume in the dual water model produces a true parallel conductivity model. However, like Waxman-Smits, it assigns the same tortuosity to both the clay and pore water current paths. This assumption seems dubious based on observations of scanning electron microscope (SEM) photos showing actual clay morphologies. Laboratory measurements of pure clay and glass beads would allow one to quantify tortuosity changes due to the introduction of clay into an otherwise pure glass bead environment. Theoretically and experimentally, the value of the clay water conductivity (Ccw) at room temperature was found to be 6.8 S/m. Therefore, for a pore water conductivity (Cw) less than 6.8, the clay adds to the rock conductivity relative to an Archie rock, as written in the Waxman-Smits model. However, when Cw is greater than 6.8, the clay water subtracts from the rock conductivity relative to an Archie rock. This cannot be accommodated by the Waxman-Smits formulation. To correct for this model deficiency, B was made a function of salinity and temperature when, theoretically, it is a function of temperature only. Thirdly, neither model accurately predicts the rock conductivity at pore water salinities below approximately 0.5 to 1 S
{"title":"The Fundamental Flaws of the Waxman-Smits and Dual Water Formulations, Attempted Remedies, and New Revelations from Historical Laboratory Complex Conductivity Measurements","authors":"John Rasmus, David Kennedy, Dean Homan","doi":"10.30632/pjv65n1-2024a1","DOIUrl":"https://doi.org/10.30632/pjv65n1-2024a1","url":null,"abstract":"The Waxman-Smits formula was introduced in 1968 as a parallel conductance model to improve previous models. A careful inspection of the Waxman and Smits model reveals it is not a parallel conduction model by the conventional definition. First, Waxman-Smits assumed that “the electrical current transported by the counterions associated with the clay travels along the same tortuous path as the current attributed to the ions in the pore water” (Waxman and Smits, 1968), removing an essential feature of a parallel conduction model, that there be two separate conductors. Based on this assumption, they assign the same geometrical factor to both current paths. The geometrical factor is defined as the reciprocal of the formation resistivity factor (1/F or σm). Waxman-Smits found experimentally that a shaly sand appeared to have an F that was larger than a clean sand and introduced F* to account for this. Therefore, the tortuosity of the current paths through the clay and the pore water were deemed to be equivalent, with both tortuosities increasing equally as the clay content increased. Second, a parallel model requires the bulk conductivity of a volume to be weighted by the fractional volumes of the separate clay and interstitial water current paths. Clavier et al. (1977) discovered during the field testing of the new 1.1-GHz electromagnetic propagation tool that there existed a volume of clay water of near-constant salinity in shales. These two concepts are not accounted for in the Waxman-Smits model. A re-evaluation of the Waxman-Smits database by Clavier et al. (1977, 1984) revealed the F* increase was primarily due to the Waxman-Smits model not accounting for the physical presence of the volume of the clay water. The inclusion of the clay water volume in the dual water model produces a true parallel conductivity model. However, like Waxman-Smits, it assigns the same tortuosity to both the clay and pore water current paths. This assumption seems dubious based on observations of scanning electron microscope (SEM) photos showing actual clay morphologies. Laboratory measurements of pure clay and glass beads would allow one to quantify tortuosity changes due to the introduction of clay into an otherwise pure glass bead environment. Theoretically and experimentally, the value of the clay water conductivity (Ccw) at room temperature was found to be 6.8 S/m. Therefore, for a pore water conductivity (Cw) less than 6.8, the clay adds to the rock conductivity relative to an Archie rock, as written in the Waxman-Smits model. However, when Cw is greater than 6.8, the clay water subtracts from the rock conductivity relative to an Archie rock. This cannot be accommodated by the Waxman-Smits formulation. To correct for this model deficiency, B was made a function of salinity and temperature when, theoretically, it is a function of temperature only. Thirdly, neither model accurately predicts the rock conductivity at pore water salinities below approximately 0.5 to 1 S","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"125 1-4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139892127","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}
Rock mechanics parameters are crucial factors for predicting rock behavior in oil and gas reservoirs, optimizing extraction strategies, and ensuring drilling safety. In this study, we propose a random forest (RF)-convolutional neural network (CNN)-long-term short-term memory network (LSTM) fusion model based on the dynamic time warping (DTW) algorithm to construct intelligent prediction models for elastic modulus, Poisson’s ratio, and compressive strength using real-time drilling engineering data. An autoencoder with a sliding window is employed to automatically identify abnormal points or segments in the calculated values of elastic modulus, Poisson’s ratio, and compressive strength obtained from drilled wells. These abnormal values are then corrected using a backpropagation (BP) neural network. Compared to single CNN-LSTM or single RF models, the RF-CNN-LSTM fusion model performs better. It achieves this by effectively combining the strengths of different algorithms in predicting outcomes. The accuracy of the RF-CNN-LSTM fusion model is over 94% when compared to the actual values. Furthermore, the analysis of the relative importance of input parameters reveals that weight on bit (WOB), temperature, displacement, equivalent circulation density (ECD), and mud density are the primary input features for predicting elastic modulus. For predicting Poisson’s ratio, the main input features include WOB, mud density, ECD, temperature, pumping pressure, displacement, and rate of penetration (ROP). Similarly, for predicting compressive strength, the main input features consist of WOB, temperature, displacement, ECD, and mud density. The research findings demonstrate that the rock mechanics parameter prediction models based on the RF-CNN-LSTM algorithm using DTW exhibit high computational accuracy in the B oil field of China. These results are significant for gaining a deeper understanding of the variations in rock mechanics parameters and optimizing drilling decisions.
{"title":"Study on Rock Mechanics Parameter Prediction Method Based on DTW Similarity and Machine-Learning Algorithms","authors":"Wenjun Cai, Jianqi Ding, Zhong Li, Zhiming Yin, Yongcun Feng","doi":"10.30632/pjv65n1-2024a7","DOIUrl":"https://doi.org/10.30632/pjv65n1-2024a7","url":null,"abstract":"Rock mechanics parameters are crucial factors for predicting rock behavior in oil and gas reservoirs, optimizing extraction strategies, and ensuring drilling safety. In this study, we propose a random forest (RF)-convolutional neural network (CNN)-long-term short-term memory network (LSTM) fusion model based on the dynamic time warping (DTW) algorithm to construct intelligent prediction models for elastic modulus, Poisson’s ratio, and compressive strength using real-time drilling engineering data. An autoencoder with a sliding window is employed to automatically identify abnormal points or segments in the calculated values of elastic modulus, Poisson’s ratio, and compressive strength obtained from drilled wells. These abnormal values are then corrected using a backpropagation (BP) neural network. Compared to single CNN-LSTM or single RF models, the RF-CNN-LSTM fusion model performs better. It achieves this by effectively combining the strengths of different algorithms in predicting outcomes. The accuracy of the RF-CNN-LSTM fusion model is over 94% when compared to the actual values. Furthermore, the analysis of the relative importance of input parameters reveals that weight on bit (WOB), temperature, displacement, equivalent circulation density (ECD), and mud density are the primary input features for predicting elastic modulus. For predicting Poisson’s ratio, the main input features include WOB, mud density, ECD, temperature, pumping pressure, displacement, and rate of penetration (ROP). Similarly, for predicting compressive strength, the main input features consist of WOB, temperature, displacement, ECD, and mud density. The research findings demonstrate that the rock mechanics parameter prediction models based on the RF-CNN-LSTM algorithm using DTW exhibit high computational accuracy in the B oil field of China. These results are significant for gaining a deeper understanding of the variations in rock mechanics parameters and optimizing drilling decisions.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"31 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139819599","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 Waxman-Smits formula was introduced in 1968 as a parallel conductance model to improve previous models. A careful inspection of the Waxman and Smits model reveals it is not a parallel conduction model by the conventional definition. First, Waxman-Smits assumed that “the electrical current transported by the counterions associated with the clay travels along the same tortuous path as the current attributed to the ions in the pore water” (Waxman and Smits, 1968), removing an essential feature of a parallel conduction model, that there be two separate conductors. Based on this assumption, they assign the same geometrical factor to both current paths. The geometrical factor is defined as the reciprocal of the formation resistivity factor (1/F or σm). Waxman-Smits found experimentally that a shaly sand appeared to have an F that was larger than a clean sand and introduced F* to account for this. Therefore, the tortuosity of the current paths through the clay and the pore water were deemed to be equivalent, with both tortuosities increasing equally as the clay content increased. Second, a parallel model requires the bulk conductivity of a volume to be weighted by the fractional volumes of the separate clay and interstitial water current paths. Clavier et al. (1977) discovered during the field testing of the new 1.1-GHz electromagnetic propagation tool that there existed a volume of clay water of near-constant salinity in shales. These two concepts are not accounted for in the Waxman-Smits model. A re-evaluation of the Waxman-Smits database by Clavier et al. (1977, 1984) revealed the F* increase was primarily due to the Waxman-Smits model not accounting for the physical presence of the volume of the clay water. The inclusion of the clay water volume in the dual water model produces a true parallel conductivity model. However, like Waxman-Smits, it assigns the same tortuosity to both the clay and pore water current paths. This assumption seems dubious based on observations of scanning electron microscope (SEM) photos showing actual clay morphologies. Laboratory measurements of pure clay and glass beads would allow one to quantify tortuosity changes due to the introduction of clay into an otherwise pure glass bead environment. Theoretically and experimentally, the value of the clay water conductivity (Ccw) at room temperature was found to be 6.8 S/m. Therefore, for a pore water conductivity (Cw) less than 6.8, the clay adds to the rock conductivity relative to an Archie rock, as written in the Waxman-Smits model. However, when Cw is greater than 6.8, the clay water subtracts from the rock conductivity relative to an Archie rock. This cannot be accommodated by the Waxman-Smits formulation. To correct for this model deficiency, B was made a function of salinity and temperature when, theoretically, it is a function of temperature only. Thirdly, neither model accurately predicts the rock conductivity at pore water salinities below approximately 0.5 to 1 S
{"title":"The Fundamental Flaws of the Waxman-Smits and Dual Water Formulations, Attempted Remedies, and New Revelations from Historical Laboratory Complex Conductivity Measurements","authors":"John Rasmus, David Kennedy, Dean Homan","doi":"10.30632/pjv65n1-2024a1","DOIUrl":"https://doi.org/10.30632/pjv65n1-2024a1","url":null,"abstract":"The Waxman-Smits formula was introduced in 1968 as a parallel conductance model to improve previous models. A careful inspection of the Waxman and Smits model reveals it is not a parallel conduction model by the conventional definition. First, Waxman-Smits assumed that “the electrical current transported by the counterions associated with the clay travels along the same tortuous path as the current attributed to the ions in the pore water” (Waxman and Smits, 1968), removing an essential feature of a parallel conduction model, that there be two separate conductors. Based on this assumption, they assign the same geometrical factor to both current paths. The geometrical factor is defined as the reciprocal of the formation resistivity factor (1/F or σm). Waxman-Smits found experimentally that a shaly sand appeared to have an F that was larger than a clean sand and introduced F* to account for this. Therefore, the tortuosity of the current paths through the clay and the pore water were deemed to be equivalent, with both tortuosities increasing equally as the clay content increased. Second, a parallel model requires the bulk conductivity of a volume to be weighted by the fractional volumes of the separate clay and interstitial water current paths. Clavier et al. (1977) discovered during the field testing of the new 1.1-GHz electromagnetic propagation tool that there existed a volume of clay water of near-constant salinity in shales. These two concepts are not accounted for in the Waxman-Smits model. A re-evaluation of the Waxman-Smits database by Clavier et al. (1977, 1984) revealed the F* increase was primarily due to the Waxman-Smits model not accounting for the physical presence of the volume of the clay water. The inclusion of the clay water volume in the dual water model produces a true parallel conductivity model. However, like Waxman-Smits, it assigns the same tortuosity to both the clay and pore water current paths. This assumption seems dubious based on observations of scanning electron microscope (SEM) photos showing actual clay morphologies. Laboratory measurements of pure clay and glass beads would allow one to quantify tortuosity changes due to the introduction of clay into an otherwise pure glass bead environment. Theoretically and experimentally, the value of the clay water conductivity (Ccw) at room temperature was found to be 6.8 S/m. Therefore, for a pore water conductivity (Cw) less than 6.8, the clay adds to the rock conductivity relative to an Archie rock, as written in the Waxman-Smits model. However, when Cw is greater than 6.8, the clay water subtracts from the rock conductivity relative to an Archie rock. This cannot be accommodated by the Waxman-Smits formulation. To correct for this model deficiency, B was made a function of salinity and temperature when, theoretically, it is a function of temperature only. Thirdly, neither model accurately predicts the rock conductivity at pore water salinities below approximately 0.5 to 1 S","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"531 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139832309","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}
Andy Hawthorn, Tonje Winther, Laurent Delabroy, Roger B. Steinsiek, Ian Leslie, Lynda Memiche, Abe Vereide
The industry is continuously challenged to improve the efficiency and safety of operations. This is evident over the last 30 years in the development and improvement of measurements acquired while drilling. However, this has, in general, until now not been applied to well integrity measurements such as casing integrity and cement evaluation, which have traditionally been acquired utilizing wireline deployment. This paper will show the results of a new drillpipe-deployed tool that can be run in parallel with existing well operations. The results from two differing North Sea wells will be compared to traditionally acquired wireline-deployed tools and will demonstrate that these measurements and the resultant interpretation can successfully be acquired on drillpipe. This allows for much improved efficiency of operations and, in fact, the ability to acquire this important data in well conditions and environments where it is difficult or, in some cases, impossible to log with conventional wireline techniques. Two wells were selected with different degrees of difficulty in terms of measurement acquisition and showing different well trajectories and mud types. Both wells were logged with both the new drillpipe-deployed technology and traditional wireline technology, allowing a direct comparison of the techniques and tools and paving the way for acceptance of the new drillpipe-conveyed technology. The new drillpipe-conveyed tool can be run anytime drillpipe is utilized in the well. A radial distribution of ultrasonic transducers arranged on the circumference of a drill collar allows for full azimuthal interpretation of the casing and cement while rotating the drillpipe. Analysis of the acquired data allows for the interpretation of caliper thickness and an evaluation of the material in the annular space behind the casing. In addition, the tool can provide casing collar location in real time and has the ability to orient downhole devices such as whipstocks, perforating guns, and oriented cutters. The two well examples conclusively demonstrate that the tool can be run in parallel with existing operations to minimize rig time and eliminate the need for a dedicated, standalone wireline operation. Also, the cement evaluation interpretation was comparable to the equivalent wireline technology. We will investigate which measurements and applications the new tool can be used for and where there may be further room for improvement.
{"title":"Changing the Game: Well Integrity Measurements Acquired on Drillpipe","authors":"Andy Hawthorn, Tonje Winther, Laurent Delabroy, Roger B. Steinsiek, Ian Leslie, Lynda Memiche, Abe Vereide","doi":"10.30632/pjv64n6-2023a2","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a2","url":null,"abstract":"The industry is continuously challenged to improve the efficiency and safety of operations. This is evident over the last 30 years in the development and improvement of measurements acquired while drilling. However, this has, in general, until now not been applied to well integrity measurements such as casing integrity and cement evaluation, which have traditionally been acquired utilizing wireline deployment. This paper will show the results of a new drillpipe-deployed tool that can be run in parallel with existing well operations. The results from two differing North Sea wells will be compared to traditionally acquired wireline-deployed tools and will demonstrate that these measurements and the resultant interpretation can successfully be acquired on drillpipe. This allows for much improved efficiency of operations and, in fact, the ability to acquire this important data in well conditions and environments where it is difficult or, in some cases, impossible to log with conventional wireline techniques. Two wells were selected with different degrees of difficulty in terms of measurement acquisition and showing different well trajectories and mud types. Both wells were logged with both the new drillpipe-deployed technology and traditional wireline technology, allowing a direct comparison of the techniques and tools and paving the way for acceptance of the new drillpipe-conveyed technology. The new drillpipe-conveyed tool can be run anytime drillpipe is utilized in the well. A radial distribution of ultrasonic transducers arranged on the circumference of a drill collar allows for full azimuthal interpretation of the casing and cement while rotating the drillpipe. Analysis of the acquired data allows for the interpretation of caliper thickness and an evaluation of the material in the annular space behind the casing. In addition, the tool can provide casing collar location in real time and has the ability to orient downhole devices such as whipstocks, perforating guns, and oriented cutters. The two well examples conclusively demonstrate that the tool can be run in parallel with existing operations to minimize rig time and eliminate the need for a dedicated, standalone wireline operation. Also, the cement evaluation interpretation was comparable to the equivalent wireline technology. We will investigate which measurements and applications the new tool can be used for and where there may be further room for improvement.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"121 51","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138608139","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}
Ian McGlynn, T. Anniyev, F. Inanc, D. Chace, Alexandr Kotov, Emmannuel Soans, Ardi Batubara
A new slim multidetector pulsed-neutron wireline-logging tool has been developed for openhole or casedhole formation evaluation saturation analysis and time-lapse monitoring. With a greater neutron source output and high-spectral resolution gamma ray detectors, the tool can be operated with reduced uncertainty or faster logging speeds. New, fully programable digital electronics provide a range of acquisition modes optimized for specific formation evaluation objectives. Neutrons are generated from a high-output pulsed-neutron generator, which propagates radially outward, passing through the borehole, completion material, and into the formation. Energy is lost through scattering, and neutrons are absorbed by the surrounding material. Gamma rays are emitted from scattering and absorption interactions at discrete energies, which can be measured by one of three spectral gamma scintillation detectors. The energy distribution of these incident gamma rays by inelastic and capture interactions is affected by the elemental composition of the material. A salinity-independent oil-water saturation assessment begins with the deconvolution of neutron-induced gamma ray inelastic spectra into constituent elemental components. Carbon-oxygen ratios (C/O) of elemental yields are then compared to a reference model to determine the relative saturation and porosity-filled volume of oil and water. In PNC (pulsed-neutron capture) acquisition mode, a salinity-dependent oil-water saturation assessment is determined from neutron capture cross section (sigma) measurements, which are compared to formation and porosity fluids using a mass balance approach. Gas saturation assessment is determined from gas-sensitive inelastic (RIN13) and capture (RATO13) ratios. Gas ratios are compared to a reference model to assess the relative saturation of fluids, typically distinguishing gas from water or gas from oil. Gas saturation is not limited to hydrocarbon components and can also be used for saturation analysis of H2, He, CO2, N2, and other non-hydrocarbon-bearing components. A new Omni-mode acquisition combining simultaneous PNC and C/O measurements was also developed. This acquisition mode provides advantages in reducing multipass logging typically required from separate PNC and C/O acquisitions. By including PNC neutron capture sigma, gas-sensitive neutron capture and inelastic measurements, and C/O inelastic measurements, the simultaneous Omni-mode (PNC+C/O) acquisition is specifically optimized for three-phase saturation analysis applications, including baseline CO2 sequestration evaluation for carbon capture, utilization, and storage (CCUS) CO2 and steamflood time-lapse monitoring. Results from a field example are presented to demonstrate the new technology with spectral C/O saturation analysis compared to traditional windows C/O analysis and to compare the performance of the next-generation tool to the legacy tool. Multiphase saturations from C/O and RIN13 measurements and comp
{"title":"Development and Baseline Comparison of a New Pulsed-Neutron Spectroscopy Tool for Carbon- Oxygen Analysis and Three-Phase Saturation Monitoring","authors":"Ian McGlynn, T. Anniyev, F. Inanc, D. Chace, Alexandr Kotov, Emmannuel Soans, Ardi Batubara","doi":"10.30632/pjv64n6-2023a7","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a7","url":null,"abstract":"A new slim multidetector pulsed-neutron wireline-logging tool has been developed for openhole or casedhole formation evaluation saturation analysis and time-lapse monitoring. With a greater neutron source output and high-spectral resolution gamma ray detectors, the tool can be operated with reduced uncertainty or faster logging speeds. New, fully programable digital electronics provide a range of acquisition modes optimized for specific formation evaluation objectives. Neutrons are generated from a high-output pulsed-neutron generator, which propagates radially outward, passing through the borehole, completion material, and into the formation. Energy is lost through scattering, and neutrons are absorbed by the surrounding material. Gamma rays are emitted from scattering and absorption interactions at discrete energies, which can be measured by one of three spectral gamma scintillation detectors. The energy distribution of these incident gamma rays by inelastic and capture interactions is affected by the elemental composition of the material. A salinity-independent oil-water saturation assessment begins with the deconvolution of neutron-induced gamma ray inelastic spectra into constituent elemental components. Carbon-oxygen ratios (C/O) of elemental yields are then compared to a reference model to determine the relative saturation and porosity-filled volume of oil and water. In PNC (pulsed-neutron capture) acquisition mode, a salinity-dependent oil-water saturation assessment is determined from neutron capture cross section (sigma) measurements, which are compared to formation and porosity fluids using a mass balance approach. Gas saturation assessment is determined from gas-sensitive inelastic (RIN13) and capture (RATO13) ratios. Gas ratios are compared to a reference model to assess the relative saturation of fluids, typically distinguishing gas from water or gas from oil. Gas saturation is not limited to hydrocarbon components and can also be used for saturation analysis of H2, He, CO2, N2, and other non-hydrocarbon-bearing components. A new Omni-mode acquisition combining simultaneous PNC and C/O measurements was also developed. This acquisition mode provides advantages in reducing multipass logging typically required from separate PNC and C/O acquisitions. By including PNC neutron capture sigma, gas-sensitive neutron capture and inelastic measurements, and C/O inelastic measurements, the simultaneous Omni-mode (PNC+C/O) acquisition is specifically optimized for three-phase saturation analysis applications, including baseline CO2 sequestration evaluation for carbon capture, utilization, and storage (CCUS) CO2 and steamflood time-lapse monitoring. Results from a field example are presented to demonstrate the new technology with spectral C/O saturation analysis compared to traditional windows C/O analysis and to compare the performance of the next-generation tool to the legacy tool. Multiphase saturations from C/O and RIN13 measurements and comp","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 25","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138620594","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}
Pub Date : 2023-12-01DOI: 10.30632/pjv64n6-2023a10
Talha H. Khan, Michael T. Myers, L. Hathon, Gabriel C. Unomah
Salt is an elastoviscoplastic material that exhibits time-dependent deformation (creep). Experimental measurements of salt creep behavior help predict underground gas repositories’ long-term geomechanical behavior. Previous time-scaling creep experiments have focused on the axial strain of unconsolidated sands. i.e., time-scaling creep effects under zero lateral strain conditions without describing the creep behavior of the radial strain. In addition, the time-scaling creep of the radial and axial strain has not been investigated in salts. A comparative testing procedure and analysis method was conducted on Spindletop salt plugs using triaxial tests for multistage triaxial tests (MST) and different holding time durations and stress regimes, resulting in time-dependent strain responses (creep tests). The MST showed evolving deformational mechanisms under the mapped yield surface based on the irrecoverable to recoverable strain ratio beginning with crack closure or conformance, plasticity, and ending at early crystal surface failure. Unlike unconsolidated sands, salts showed both time and strain amplitude scaling. The axial and radial strain data show scaling behavior under low and high levels of deviatoric stress separated by a transitional period. The salt showed only an axial creep response at low deviatoric stress distally from the yield surface (one-dimesional (1D) response or zero lateral strain), which indicates negative dilatant deformation or uniaxial compaction. In contrast, the salts showed equal strain amplitude scaling factors both axially and radially at high deviatoric stress proximal to the yield surface (two-dimensional (2D) response or unconstrained boundary condition), which suggests positive dilatant deformation. Microstructural images showed accumulated creep damage under high deviatoric stress associated with parallel planes of dislocation-intergranular slip, microcracking, and compaction-induced dilational strains. The period of scaling is interpreted as regions where a single mechanism is dominating. Strain amplitude scaling for both low and high deviatoric creep stress tests provides inputs for a constitutive model of creep response in understanding the magnitude of mechanical damage associated with time-independent stress-strain curves in salts for the structural integrity of salt caverns during cyclic fluid injection and depletion.
{"title":"Time-Scaling Creep in Salt Rocks for Underground Storage","authors":"Talha H. Khan, Michael T. Myers, L. Hathon, Gabriel C. Unomah","doi":"10.30632/pjv64n6-2023a10","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a10","url":null,"abstract":"Salt is an elastoviscoplastic material that exhibits time-dependent deformation (creep). Experimental measurements of salt creep behavior help predict underground gas repositories’ long-term geomechanical behavior. Previous time-scaling creep experiments have focused on the axial strain of unconsolidated sands. i.e., time-scaling creep effects under zero lateral strain conditions without describing the creep behavior of the radial strain. In addition, the time-scaling creep of the radial and axial strain has not been investigated in salts. A comparative testing procedure and analysis method was conducted on Spindletop salt plugs using triaxial tests for multistage triaxial tests (MST) and different holding time durations and stress regimes, resulting in time-dependent strain responses (creep tests). The MST showed evolving deformational mechanisms under the mapped yield surface based on the irrecoverable to recoverable strain ratio beginning with crack closure or conformance, plasticity, and ending at early crystal surface failure. Unlike unconsolidated sands, salts showed both time and strain amplitude scaling. The axial and radial strain data show scaling behavior under low and high levels of deviatoric stress separated by a transitional period. The salt showed only an axial creep response at low deviatoric stress distally from the yield surface (one-dimesional (1D) response or zero lateral strain), which indicates negative dilatant deformation or uniaxial compaction. In contrast, the salts showed equal strain amplitude scaling factors both axially and radially at high deviatoric stress proximal to the yield surface (two-dimensional (2D) response or unconstrained boundary condition), which suggests positive dilatant deformation. Microstructural images showed accumulated creep damage under high deviatoric stress associated with parallel planes of dislocation-intergranular slip, microcracking, and compaction-induced dilational strains. The period of scaling is interpreted as regions where a single mechanism is dominating. Strain amplitude scaling for both low and high deviatoric creep stress tests provides inputs for a constitutive model of creep response in understanding the magnitude of mechanical damage associated with time-independent stress-strain curves in salts for the structural integrity of salt caverns during cyclic fluid injection and depletion.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" July","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138611110","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 complexity of the microstructure and fluids in unconventional reservoirs presents challenges to the traditional approaches to the evaluation of geological formations and petrophysical properties due to the low porosity, ultralow permeability, complex lithology, and fluid composition. Nuclear magnetic resonance (NMR) techniques have been playing major roles in unconventional shale characterization in the last decades as NMR can provide critical information about the reservoirs for quantifying their petrophysical parameters and fluid properties and estimating productivity. Laboratory NMR techniques at higher frequency (HF), e.g., 23 MHz, especially two-dimensional (2D) T1-T2 mapping, and their applications have been essential for the noninvasive characterization of tight rock samples for identifying kerogen, bitumen, heavy or light hydrocarbons, and bound or capillary water. Traditional T2 cutoffs, established with low frequency (LF) NMR, no longer apply and need new definitions to reflect the inferences from water and hydrocarbons separately. The crushed rock analysis method, as applied to unconventional formations, has been successful in evaluating total porosity and water saturation but also suffers from inconsistency in results due to desiccation and solvent effects. In the past decade, the oil and gas industry has witnessed significant development of HF NMR techniques that couple advances in petrophysics, petroleum engineering, and geochemistry with a broad range of applications. It is necessary to review such technological advances and draw conclusions to benefit unconventional core analysis programs. This article will summarize key advances in laboratory NMR applications in unconventional shale characterization, including monitoring processes of liquids equilibrium, desiccation, and imbibition in fresh shale samples, determination of activation energy of hydrocarbons in shales, monitoring changes in a shale sample during liquid flooding experiments, and direct measurements on kerogen.
{"title":"Applications of Two-Dimensional Laboratory Higher-Frequency NMR in Unconventional Shale Characterization","authors":"Z. H. Xie, Omar Reffell","doi":"10.30632/pjv64n6-2023a3","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a3","url":null,"abstract":"The complexity of the microstructure and fluids in unconventional reservoirs presents challenges to the traditional approaches to the evaluation of geological formations and petrophysical properties due to the low porosity, ultralow permeability, complex lithology, and fluid composition. Nuclear magnetic resonance (NMR) techniques have been playing major roles in unconventional shale characterization in the last decades as NMR can provide critical information about the reservoirs for quantifying their petrophysical parameters and fluid properties and estimating productivity. Laboratory NMR techniques at higher frequency (HF), e.g., 23 MHz, especially two-dimensional (2D) T1-T2 mapping, and their applications have been essential for the noninvasive characterization of tight rock samples for identifying kerogen, bitumen, heavy or light hydrocarbons, and bound or capillary water. Traditional T2 cutoffs, established with low frequency (LF) NMR, no longer apply and need new definitions to reflect the inferences from water and hydrocarbons separately. The crushed rock analysis method, as applied to unconventional formations, has been successful in evaluating total porosity and water saturation but also suffers from inconsistency in results due to desiccation and solvent effects. In the past decade, the oil and gas industry has witnessed significant development of HF NMR techniques that couple advances in petrophysics, petroleum engineering, and geochemistry with a broad range of applications. It is necessary to review such technological advances and draw conclusions to benefit unconventional core analysis programs. This article will summarize key advances in laboratory NMR applications in unconventional shale characterization, including monitoring processes of liquids equilibrium, desiccation, and imbibition in fresh shale samples, determination of activation energy of hydrocarbons in shales, monitoring changes in a shale sample during liquid flooding experiments, and direct measurements on kerogen.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"348 16‐17","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138625722","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}
It is challenging to reliably identify fluid components and estimate their saturations in formations with complex lithology, complex pore structure, or varying wettability conditions. Common practices for assessing fluid saturations rely on the interpretation of resistivity measurements. These techniques require model calibration, which is time consuming/expensive and can only differentiate conductive and nonconductive fluids. Interpretation of 2D NMR maps provides a viable alternative for identifying fluid components and fluid volumes. However, conventional techniques for the interpretation of 2D NMR rely on cutoffs in the T1-T2 or D-T2 maps. The application of cutoffs is prone to inaccuracies when fluid-component relaxation responses overlap. To address these shortcomings, we introduce a new workflow for identifying/tracking fluid components and estimating their volumes from the interpretation of 2D NMR measurements. We developed a workflow that approximates 2D NMR maps with a superposition of 2D Gaussian distributions. The algorithm automatically determines the optimum number of Gaussian distributions and their corresponding properties (i.e., amplitudes, variances, and means). Next, a clustering technique is implemented to the dataspace containing the Gaussian distribution parameters obtained for the entire logged interval. Each Gaussian is assigned to a cluster corresponding to different pore/fluid components. We then calculate the volumes under the Gaussian distributions corresponding to each cluster at each depth. The volumes associated with each cluster translate directly into the pore volumes corresponding to the different fluid components (e.g., heavy/light hydrocarbon, bound/free water) at each depth. A highlighted contribution of this work is that, in contrast to the alternative petrophysical interpretation techniques for fluid characterization, the introduced workflow does not require calibration efforts, user-defined cutoffs, or proprietary data sets. Furthermore, approximating 2D NMR data with a superposition of Gaussian distributions improves the accuracy of estimated pore volumes of fluid components with overlapping NMR responses. The clustering using the Gaussian distribution parameters as inputs enables depth tracking of different fluid components without making use of user-defined 2D cutoffs. Finally, the multidimensional nature of the introduced clustering provides the unique capability of identifying different fluid components with 2D NMR response located in the same range of coordinates in a T1-T2 map. We successfully verified the reliability and robustness of the new workflow for enhancing petrophysical interpretation in two organic-rich mudrock formations with complex mineralogy and pore structure.
{"title":"A New Workflow for Assessment of Fluid Components and Pore Volumes From 2D NMR Measurements in Formations With Complex Mineralogy and Pore Structure","authors":"Artur Posenato Garcia, R. Mallan, Boquin Sun","doi":"10.30632/pjv64n6-2023a5","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a5","url":null,"abstract":"It is challenging to reliably identify fluid components and estimate their saturations in formations with complex lithology, complex pore structure, or varying wettability conditions. Common practices for assessing fluid saturations rely on the interpretation of resistivity measurements. These techniques require model calibration, which is time consuming/expensive and can only differentiate conductive and nonconductive fluids. Interpretation of 2D NMR maps provides a viable alternative for identifying fluid components and fluid volumes. However, conventional techniques for the interpretation of 2D NMR rely on cutoffs in the T1-T2 or D-T2 maps. The application of cutoffs is prone to inaccuracies when fluid-component relaxation responses overlap. To address these shortcomings, we introduce a new workflow for identifying/tracking fluid components and estimating their volumes from the interpretation of 2D NMR measurements. We developed a workflow that approximates 2D NMR maps with a superposition of 2D Gaussian distributions. The algorithm automatically determines the optimum number of Gaussian distributions and their corresponding properties (i.e., amplitudes, variances, and means). Next, a clustering technique is implemented to the dataspace containing the Gaussian distribution parameters obtained for the entire logged interval. Each Gaussian is assigned to a cluster corresponding to different pore/fluid components. We then calculate the volumes under the Gaussian distributions corresponding to each cluster at each depth. The volumes associated with each cluster translate directly into the pore volumes corresponding to the different fluid components (e.g., heavy/light hydrocarbon, bound/free water) at each depth. A highlighted contribution of this work is that, in contrast to the alternative petrophysical interpretation techniques for fluid characterization, the introduced workflow does not require calibration efforts, user-defined cutoffs, or proprietary data sets. Furthermore, approximating 2D NMR data with a superposition of Gaussian distributions improves the accuracy of estimated pore volumes of fluid components with overlapping NMR responses. The clustering using the Gaussian distribution parameters as inputs enables depth tracking of different fluid components without making use of user-defined 2D cutoffs. Finally, the multidimensional nature of the introduced clustering provides the unique capability of identifying different fluid components with 2D NMR response located in the same range of coordinates in a T1-T2 map. We successfully verified the reliability and robustness of the new workflow for enhancing petrophysical interpretation in two organic-rich mudrock formations with complex mineralogy and pore structure.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 40","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138620638","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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