Klemens Katterbauer, W. Dokhon, Fahmi Aulia, Mohanad M. Fahmi
Corrosion in pipes is a major challenge for the oil and gas industry as the metal loss of the pipe, as well as solid buildup in the pipe, may lead to an impediment of flow assurance or may lead to hindering well performance. Therefore, managing well integrity by stringent monitoring and predicting corrosion of the well is quintessential for maximizing the productive life of the wells and minimizing the risk of well control issues, which subsequently minimizing cost related to corrosion log allocation and workovers. We present a novel supervised learning method for a corrosion monitoring and prediction system in real time. The system analyzes in real time various parameters of major causes of corrosion such as salt water, hydrogen sulfide, CO2, well age, fluid rate, metal losses, and other parameters. The data are preprocessed with a filter to remove outliers and inconsistencies in the data. The filter cross-correlates the various parameters to determine the input weights for the deep learning classification techniques. The wells are classified in terms of their need for a workover, then by the framework based on the data, utilizing a two-dimensional segmentation approach for the severity as well as risk for each well. The framework was trialed on a probabilistically determined large dataset of a group of wells with an assumed metal loss. The framework was first trained on the training dataset, and then subsequently evaluated on a different test well set. The training results were robust with a strong ability to estimate metal losses and corrosion classification. Segmentation on the test wells outlined strong segmentation capabilities, while facing challenges in the segmentation when the quantified risk for a well is medium. The novel framework presents a data-driven approach to the fast and efficient characterization of wells as potential candidates for corrosion logs and workover. The framework can be easily expanded with new well data for improving classification.
{"title":"A Novel Corrosion Monitoring and Prediction System Utilizing Advanced Artificial Intelligence","authors":"Klemens Katterbauer, W. Dokhon, Fahmi Aulia, Mohanad M. Fahmi","doi":"10.2118/204580-ms","DOIUrl":"https://doi.org/10.2118/204580-ms","url":null,"abstract":"\u0000 Corrosion in pipes is a major challenge for the oil and gas industry as the metal loss of the pipe, as well as solid buildup in the pipe, may lead to an impediment of flow assurance or may lead to hindering well performance. Therefore, managing well integrity by stringent monitoring and predicting corrosion of the well is quintessential for maximizing the productive life of the wells and minimizing the risk of well control issues, which subsequently minimizing cost related to corrosion log allocation and workovers.\u0000 We present a novel supervised learning method for a corrosion monitoring and prediction system in real time. The system analyzes in real time various parameters of major causes of corrosion such as salt water, hydrogen sulfide, CO2, well age, fluid rate, metal losses, and other parameters. The data are preprocessed with a filter to remove outliers and inconsistencies in the data. The filter cross-correlates the various parameters to determine the input weights for the deep learning classification techniques. The wells are classified in terms of their need for a workover, then by the framework based on the data, utilizing a two-dimensional segmentation approach for the severity as well as risk for each well.\u0000 The framework was trialed on a probabilistically determined large dataset of a group of wells with an assumed metal loss. The framework was first trained on the training dataset, and then subsequently evaluated on a different test well set. The training results were robust with a strong ability to estimate metal losses and corrosion classification. Segmentation on the test wells outlined strong segmentation capabilities, while facing challenges in the segmentation when the quantified risk for a well is medium.\u0000 The novel framework presents a data-driven approach to the fast and efficient characterization of wells as potential candidates for corrosion logs and workover. The framework can be easily expanded with new well data for improving classification.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"90 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77671840","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}
Sediment volumetric budget estimates are very important input parameters for process-based depositional modelling (forward stratigraphic modelling). This paper presents a new integrated approach for analyze sediment volumetric budgets in sedimentary basins that is based on the reconstruction of regional grain size trends. In subsurface studies of sediment routing systems, noticeable uncertainties in estimated total sediment volumes occur when available datasets are limited to local areas that do not cover the entire sediment routing system. These uncertainties also affect models of catchment areas, structural uplift, and denudation rates as well as net:gross predictions. The new integrated approach focuses on reconstructing sediment budgets for entire sediment fairways from limited local datasets. It uses a combination of sediment mass balancing and local grain size distributions to predict basin-wide grain size distributions. The comparison of local grain size to fairway-scale grain size trends is key in correcting sediment volumetrics for significantly reduced uncertainties in catchment reconstruction and net:gross ratios predictions at the scale of sediment fairways, sub-basins, prospects and exploration/production fields. The new approach has been applied successfully to two subsurface continental to marine delta systems. They cover periods of approximately 7 My in total and include four limited local areas of interest (AOI). These local AOIs measure 200×200 km, while the entire sub-basin measures 500×800 km. The new approach indicates that only up to 40% of the total sediment volume of each fairway could be captured by previous methodologies with limited local areas of interest. A maximum of 70% of the entire sink sediment volume could be incorporated in local areas of interest. The new approach presented in this paper significantly lowers the uncertainties in sediment volume estimates, depositional rates and lithology distribution input parameters in forward stratigraphic modelling. For the two case studies, previous sediment flux models indicated rates of 10,000 km/Myr. The new integrated approach indicates that sediment flux actually reached 30,000 km/Myr with major implications for sediment distribution, net:gross prediction and catchment size and denudation rates estimates. The new integrated approach reduces uncertainties in catchment size and tectonic exhumation rate estimates for clastic depositional systems. It provides lower uncertainty parameters (sediment volume, source locations, sediment fractions, diffusion coefficients) for forward stratigraphic modelling, e.g., for reservoir quality prediction in hydrocarbon exploration. In fundamental research, provenance analyses can be better constrained by improved catchment size prediction and sediment grain size distribution models for sink areas
{"title":"New Workflow of Sediment Mass Balancing, from Local Datasets, for Predicting Basin Scale Trends","authors":"N. Michael, R. Zűhlke","doi":"10.2118/204591-ms","DOIUrl":"https://doi.org/10.2118/204591-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Sediment volumetric budget estimates are very important input parameters for process-based depositional modelling (forward stratigraphic modelling). This paper presents a new integrated approach for analyze sediment volumetric budgets in sedimentary basins that is based on the reconstruction of regional grain size trends. In subsurface studies of sediment routing systems, noticeable uncertainties in estimated total sediment volumes occur when available datasets are limited to local areas that do not cover the entire sediment routing system. These uncertainties also affect models of catchment areas, structural uplift, and denudation rates as well as net:gross predictions.\u0000 \u0000 \u0000 \u0000 The new integrated approach focuses on reconstructing sediment budgets for entire sediment fairways from limited local datasets. It uses a combination of sediment mass balancing and local grain size distributions to predict basin-wide grain size distributions. The comparison of local grain size to fairway-scale grain size trends is key in correcting sediment volumetrics for significantly reduced uncertainties in catchment reconstruction and net:gross ratios predictions at the scale of sediment fairways, sub-basins, prospects and exploration/production fields.\u0000 \u0000 \u0000 \u0000 The new approach has been applied successfully to two subsurface continental to marine delta systems. They cover periods of approximately 7 My in total and include four limited local areas of interest (AOI). These local AOIs measure 200×200 km, while the entire sub-basin measures 500×800 km. The new approach indicates that only up to 40% of the total sediment volume of each fairway could be captured by previous methodologies with limited local areas of interest. A maximum of 70% of the entire sink sediment volume could be incorporated in local areas of interest. The new approach presented in this paper significantly lowers the uncertainties in sediment volume estimates, depositional rates and lithology distribution input parameters in forward stratigraphic modelling. For the two case studies, previous sediment flux models indicated rates of 10,000 km/Myr. The new integrated approach indicates that sediment flux actually reached 30,000 km/Myr with major implications for sediment distribution, net:gross prediction and catchment size and denudation rates estimates.\u0000 \u0000 \u0000 \u0000 The new integrated approach reduces uncertainties in catchment size and tectonic exhumation rate estimates for clastic depositional systems. It provides lower uncertainty parameters (sediment volume, source locations, sediment fractions, diffusion coefficients) for forward stratigraphic modelling, e.g., for reservoir quality prediction in hydrocarbon exploration. In fundamental research, provenance analyses can be better constrained by improved catchment size prediction and sediment grain size distribution models for sink areas\u0000","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76222317","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}
Modern dielectric tools are often run to obtain fundamental formation properties, such as remaining oil saturation, water-filled porosity, and brine salinity. Techniques to extract more challenging reservoir petrophysical properties like Archie m and n parameters are also emerging. The accuracy and representativeness of the obtained petrophysical parameters depend on the input parameter accuracy, such as matrix permittivity. In carbonates, matrix permittivity is known to vary over a wide range, for example, limestone matrix permittivity reported in the literature ranges from 7.5 to 9.2. The main objective of the current study is to reduce matrix dielectric permittivity uncertainty for enhanced formation evaluation in carbonate reservoirs. All dielectric measurements were conducted on 1.5 in. carbonate plug samples by means of a coaxial reflection probe with a range of frequency between 10 MHz and 1 GHz. To calculate matrix mineral dielectric permittivity, sample porosity must be obtained. Stress-corrected helium porosity from routine core analysis is used and samples mineralogy and chemical composition are measured by X-Ray diffraction. Dielectric system calibration is done by utilizing several well-characterized standards with known dielectric properties. Calcite and dolomite matrix permittivity are assessed by laboratory measurements. Results of this study and based on data from 180 core plugs allowed to assess the validity of the defined errors by statistical analysis, resulting in much reduced uncertainties in carbonate rock matrix dielectric permittivity; thus enhancing formation evaluation using dielectric measurements. The current study provides better control on dielectric permittivity values used in dielectric log interpretation for limestone formations. Such knowledge will provide better confidence in interpreted data such as water-filled porosity, flushed zone salinity and water phase tortuosity.
{"title":"Matrix Dielectric Permittivity for Enhanced Formation Evaluation","authors":"Wael Abdallah, A. Al-Zoukani, S. Ma","doi":"10.2118/204886-ms","DOIUrl":"https://doi.org/10.2118/204886-ms","url":null,"abstract":"\u0000 Modern dielectric tools are often run to obtain fundamental formation properties, such as remaining oil saturation, water-filled porosity, and brine salinity. Techniques to extract more challenging reservoir petrophysical properties like Archie m and n parameters are also emerging. The accuracy and representativeness of the obtained petrophysical parameters depend on the input parameter accuracy, such as matrix permittivity. In carbonates, matrix permittivity is known to vary over a wide range, for example, limestone matrix permittivity reported in the literature ranges from 7.5 to 9.2. The main objective of the current study is to reduce matrix dielectric permittivity uncertainty for enhanced formation evaluation in carbonate reservoirs. All dielectric measurements were conducted on 1.5 in. carbonate plug samples by means of a coaxial reflection probe with a range of frequency between 10 MHz and 1 GHz. To calculate matrix mineral dielectric permittivity, sample porosity must be obtained. Stress-corrected helium porosity from routine core analysis is used and samples mineralogy and chemical composition are measured by X-Ray diffraction. Dielectric system calibration is done by utilizing several well-characterized standards with known dielectric properties. Calcite and dolomite matrix permittivity are assessed by laboratory measurements. Results of this study and based on data from 180 core plugs allowed to assess the validity of the defined errors by statistical analysis, resulting in much reduced uncertainties in carbonate rock matrix dielectric permittivity; thus enhancing formation evaluation using dielectric measurements. The current study provides better control on dielectric permittivity values used in dielectric log interpretation for limestone formations. Such knowledge will provide better confidence in interpreted data such as water-filled porosity, flushed zone salinity and water phase tortuosity.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78736809","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}
E. Buzi, H. Seren, Thomas Hillman, Tim Thiel, M. Deffenbaugh, A. Bukhamseen, Mohamed Larbi Zeghlache
The latest development in the electronics and manufacturing industry has enabled work towards the modernization of oil-field instruments. As a part of this trend, it is the time to invent and design small size oil-field instruments that could be much more practical to handle, easy to use, and less costly. High temperatures and pressures of the downhole environment make it very challenging to design and further develop such downhole instruments. To create such apparatuses, a thorough study of downhole conditions needs to be done upfront. This study will further help to define the design specifications and requirements. By targeting liquid wells in Saudi Arabia, we have overcome the challenges posed by the harsh downhole environment and managed to design and manufacture a hand-held device called ‘Sensor Ball’ and tested it in the field.
{"title":"Sensor Ball: Modernized Logging","authors":"E. Buzi, H. Seren, Thomas Hillman, Tim Thiel, M. Deffenbaugh, A. Bukhamseen, Mohamed Larbi Zeghlache","doi":"10.2118/204791-ms","DOIUrl":"https://doi.org/10.2118/204791-ms","url":null,"abstract":"\u0000 The latest development in the electronics and manufacturing industry has enabled work towards the modernization of oil-field instruments. As a part of this trend, it is the time to invent and design small size oil-field instruments that could be much more practical to handle, easy to use, and less costly. High temperatures and pressures of the downhole environment make it very challenging to design and further develop such downhole instruments. To create such apparatuses, a thorough study of downhole conditions needs to be done upfront. This study will further help to define the design specifications and requirements. By targeting liquid wells in Saudi Arabia, we have overcome the challenges posed by the harsh downhole environment and managed to design and manufacture a hand-held device called ‘Sensor Ball’ and tested it in the field.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"32 12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80234066","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}
S. Muhammad, Mohammed Kurdi, A. Momin, Muzzammil Shakeel, Roberto Vega, Yvan Simmons
The multistage hydraulic fracturing technique is considered to be one of the most effective stimulation techniques used for exploiting unconventional plays. The use of dissolvable frac plugs in multistage hydraulic fracturing has the potential to reduce well intervention requirements. Applicability of dissolvable frac plugs, as an integral part of plug and perf operations, in Middle East unconventional plays presents a myriad of technical challenges associated with high-pressure and high-temperature (HPHT) well conditions. Two counteracting drivers coexist in dissolvable frac plug design: 1) The need for the frac plug to withstand well conditions during the entire frac stage operational cycle and 2) the requirement for the frac plug to dissolve as quickly as possible after the stimulation treatment has been placed. The HPHT conditions of the wells utilizing dissolvable frac plugs adds to the complexity of not only the plug design, but also its associated deployment operational procedures. The main premise of the functional methodology of dissolvable frac plugs involves a chain reaction being triggered in the presence of specific fluids under specific temperature conditions. After the commencement of the degradation/dissolution chain reaction process, the useful lifetime of the frac plug begins to deplete, where the degradation chain reaction accelerates with increasing temperature exposure. Site operations will then conform to expedited practices to minimize undesired exposure time. This would minimize the risks of degradation/dissolution before plug setting, plug test, and actual stimulation treatment placement. Based on the HPHT well conditions of Middle Eastern unconventional plays, a structured process was put in place to satisfy the define, assess, select, and execute phases of the initiative The inevitable occurrences of unforeseen complications during operational deployments served to accelerate the learning curve for the continued utilization of dissolvable frac plugs. Operational issues ranging from electric line unit complications to frac pump downtime during the initial frac plug deployments compromised the structural integrity and functionality of the dissolvable frac plugs. Recognizing that exposure time was critical to maintaining the structural integrity of the plug, best practices were derived and enforced to minimize said exposure time. In addition, slight design modifications were made to specific components of the plug to increase its robustness while not compromising the desired degradation rates. The adoption of these mitigating measures has resulted in the acceptance of the dissolvable frac plug as the standard plug option for all plug and perf operations. The vast experience gained during the deployment of more than 1,000 dissolvable frac plugs for hydraulic fracturing stages in a Middle Eastern country has served as a basis to conceive a list of best practices to address mitigating unforeseen complications. These best
{"title":"Best Practices and Lessons Learned in Deploying and Setting Dissolvable Frac Plugs in Middle East at HPHT Conditions","authors":"S. Muhammad, Mohammed Kurdi, A. Momin, Muzzammil Shakeel, Roberto Vega, Yvan Simmons","doi":"10.2118/204745-ms","DOIUrl":"https://doi.org/10.2118/204745-ms","url":null,"abstract":"\u0000 The multistage hydraulic fracturing technique is considered to be one of the most effective stimulation techniques used for exploiting unconventional plays. The use of dissolvable frac plugs in multistage hydraulic fracturing has the potential to reduce well intervention requirements. Applicability of dissolvable frac plugs, as an integral part of plug and perf operations, in Middle East unconventional plays presents a myriad of technical challenges associated with high-pressure and high-temperature (HPHT) well conditions. Two counteracting drivers coexist in dissolvable frac plug design: 1) The need for the frac plug to withstand well conditions during the entire frac stage operational cycle and 2) the requirement for the frac plug to dissolve as quickly as possible after the stimulation treatment has been placed. The HPHT conditions of the wells utilizing dissolvable frac plugs adds to the complexity of not only the plug design, but also its associated deployment operational procedures.\u0000 The main premise of the functional methodology of dissolvable frac plugs involves a chain reaction being triggered in the presence of specific fluids under specific temperature conditions. After the commencement of the degradation/dissolution chain reaction process, the useful lifetime of the frac plug begins to deplete, where the degradation chain reaction accelerates with increasing temperature exposure. Site operations will then conform to expedited practices to minimize undesired exposure time. This would minimize the risks of degradation/dissolution before plug setting, plug test, and actual stimulation treatment placement. Based on the HPHT well conditions of Middle Eastern unconventional plays, a structured process was put in place to satisfy the define, assess, select, and execute phases of the initiative\u0000 The inevitable occurrences of unforeseen complications during operational deployments served to accelerate the learning curve for the continued utilization of dissolvable frac plugs. Operational issues ranging from electric line unit complications to frac pump downtime during the initial frac plug deployments compromised the structural integrity and functionality of the dissolvable frac plugs. Recognizing that exposure time was critical to maintaining the structural integrity of the plug, best practices were derived and enforced to minimize said exposure time. In addition, slight design modifications were made to specific components of the plug to increase its robustness while not compromising the desired degradation rates. The adoption of these mitigating measures has resulted in the acceptance of the dissolvable frac plug as the standard plug option for all plug and perf operations.\u0000 The vast experience gained during the deployment of more than 1,000 dissolvable frac plugs for hydraulic fracturing stages in a Middle Eastern country has served as a basis to conceive a list of best practices to address mitigating unforeseen complications. These best","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"106 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80418416","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}
Loss of circulation is one of the greatest challenges that are frequently encountered while drilling. Various types of LCM products are used by the industry to combat loss of circulation. Characterization of these LCM products is very important to select the most suitable products to improve the success rate of LCM treatment jobs. This paper describes the theoretical basis of the application of strain energy along with the development of a strain energy-based mathematical model to create a dedicated software driven novel method and test apparatus for quick and reliable measurement of the coefficient of resiliency of various LCM products to improve the likelihood and probability of success rate of LCM treatment jobs. The simple but reliable method and apparatus provide a fit-for-purpose solution for additional characterization of LCM products. The design and construction of the test device and the development of the method considered the most critical technical factors that have high impact on data reliability, data accuracy, repeatability and data sensitivity. The components of the test device were selected based on technical, economical, portability and ease of operation using a dedicated software driven method and data acquisition system. Experimental results generated by loading and unloading a particular mass of a LCM product under a constant displacement rate of the loading foot of the test apparatus demonstrated the suitability of the method and the apparatus in determining the coefficient of resiliency of LCM products. Based on the area below the loading curve i.e. the strain energy absorbed during the loading cycle and the area below the unloading curve i.e. the strain energy desorbed during the unloading cycle, the data acquisition software automatically calculates the coefficient of resiliency of the LCM products. The resilient characteristic of LCM products is one of the critical factors that is very important for high performance pill or slurry design to enhance the seal/plug stability. Hence, the newly developed method and apparatus will play a positive role to improve the probability and the likelihood of creating a stable and lasting seal/plug in the loss zones. As loss control materials with good resilient properties are highly adaptable in changing stress and pressure conditions, this method can provide appropriate guidelines to mud chemists, mud engineers and mud consultants in designing high performance LCM blends or slurries to combat moderate and severe loss of circulation.
{"title":"Apparatus and Method for Strain Energy Based Resiliency Measurement of Loss Control Materials","authors":"M. Amanullah, Raed Alouhali, Mohammed Alarfaj","doi":"10.2118/204782-ms","DOIUrl":"https://doi.org/10.2118/204782-ms","url":null,"abstract":"\u0000 Loss of circulation is one of the greatest challenges that are frequently encountered while drilling. Various types of LCM products are used by the industry to combat loss of circulation. Characterization of these LCM products is very important to select the most suitable products to improve the success rate of LCM treatment jobs. This paper describes the theoretical basis of the application of strain energy along with the development of a strain energy-based mathematical model to create a dedicated software driven novel method and test apparatus for quick and reliable measurement of the coefficient of resiliency of various LCM products to improve the likelihood and probability of success rate of LCM treatment jobs. The simple but reliable method and apparatus provide a fit-for-purpose solution for additional characterization of LCM products.\u0000 The design and construction of the test device and the development of the method considered the most critical technical factors that have high impact on data reliability, data accuracy, repeatability and data sensitivity. The components of the test device were selected based on technical, economical, portability and ease of operation using a dedicated software driven method and data acquisition system.\u0000 Experimental results generated by loading and unloading a particular mass of a LCM product under a constant displacement rate of the loading foot of the test apparatus demonstrated the suitability of the method and the apparatus in determining the coefficient of resiliency of LCM products. Based on the area below the loading curve i.e. the strain energy absorbed during the loading cycle and the area below the unloading curve i.e. the strain energy desorbed during the unloading cycle, the data acquisition software automatically calculates the coefficient of resiliency of the LCM products.\u0000 The resilient characteristic of LCM products is one of the critical factors that is very important for high performance pill or slurry design to enhance the seal/plug stability. Hence, the newly developed method and apparatus will play a positive role to improve the probability and the likelihood of creating a stable and lasting seal/plug in the loss zones. As loss control materials with good resilient properties are highly adaptable in changing stress and pressure conditions, this method can provide appropriate guidelines to mud chemists, mud engineers and mud consultants in designing high performance LCM blends or slurries to combat moderate and severe loss of circulation.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"183 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85615165","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}
P. Nivlet, Yunlai Yang, A. Magana-Mora, M. Abughaban, Ayodeji Abegunde
Overpressure refers to the abnormally high subsurface pressure that may exceed hydrostatic pressure at a given depth. Its characterization is an important part of subsurface characterization as it allows to complete drilling operations in a safe and optimal way. In dolomitic formations, however, the prediction of such overpressure is especially challenging because of (1) the high degree of lateral variability of the formations, (2) the limited effect of overpressure on tight rocks elastic parameters, and (3) the complexity of physical processes involved to form overpressure. In addition to these factors, existing experimental models generally used to relate elastic parameters to pressure are often not well calibrated to carbonate rocks. The alternative to existing purely physical approaches is a data-driven model that leverages data from offset wells. We show that due to the complexity of the characterization question to be solved, an end-to-end machine learning based approach is deemed to fail. Instead of a fully automated approach, we show a semi-supervised workflow that integrates seismic, geological data, and overpressure observations from previously drilled wells to map overpressure regions. Attribute maps are first extracted from a 3D seismic data set in an overpressured geological formation of interest. An auto-encoder is then used to learn a more compact representation of data, resulting in a reduced number of latent attributes. Then, a hand-tailored semi-supervised approach is applied, which is a combination of clustering method (here based on DBSCAN algorithm) and Bayesian classification to determine overpressure risk degree (no risk, mild, or high risk). The approach described in this study is compared to direct end-to-end models and significantly outperforms them with an error on a blind well prediction of around 25%. The overpressure probability maps resulting from the models can be used later for the optimization of drilling processes and to reduce drilling hazards.
{"title":"A Machine-Learning Based Workflow for Predicting Overpressure in a Stiff Dolomitic Formation","authors":"P. Nivlet, Yunlai Yang, A. Magana-Mora, M. Abughaban, Ayodeji Abegunde","doi":"10.2118/204844-ms","DOIUrl":"https://doi.org/10.2118/204844-ms","url":null,"abstract":"\u0000 Overpressure refers to the abnormally high subsurface pressure that may exceed hydrostatic pressure at a given depth. Its characterization is an important part of subsurface characterization as it allows to complete drilling operations in a safe and optimal way. In dolomitic formations, however, the prediction of such overpressure is especially challenging because of (1) the high degree of lateral variability of the formations, (2) the limited effect of overpressure on tight rocks elastic parameters, and (3) the complexity of physical processes involved to form overpressure. In addition to these factors, existing experimental models generally used to relate elastic parameters to pressure are often not well calibrated to carbonate rocks. The alternative to existing purely physical approaches is a data-driven model that leverages data from offset wells. We show that due to the complexity of the characterization question to be solved, an end-to-end machine learning based approach is deemed to fail. Instead of a fully automated approach, we show a semi-supervised workflow that integrates seismic, geological data, and overpressure observations from previously drilled wells to map overpressure regions. Attribute maps are first extracted from a 3D seismic data set in an overpressured geological formation of interest. An auto-encoder is then used to learn a more compact representation of data, resulting in a reduced number of latent attributes. Then, a hand-tailored semi-supervised approach is applied, which is a combination of clustering method (here based on DBSCAN algorithm) and Bayesian classification to determine overpressure risk degree (no risk, mild, or high risk). The approach described in this study is compared to direct end-to-end models and significantly outperforms them with an error on a blind well prediction of around 25%. The overpressure probability maps resulting from the models can be used later for the optimization of drilling processes and to reduce drilling hazards.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76203077","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}
Jelena Skenderija, Alexis Koulidis, V. Kelessidis, Shehab Ahmed
Challenging wells require an accurate hydraulic model to achieve maximum performance for drilling applications. This work was conducted with a simulator capable of recreating the actual drilling process, including on-the-fly adjustments of the drilling parameters. The paper focuses on the predictions of the drilling simulator's pressure losses inside the drill string and across the open-hole and casing annuli applying the most common rheological models. Comparison is then made with pressure losses from field data. Drilling data of vertical and deviated wells were acquired to recreate the actual drilling environment and wellbore design. Several sections with a variety of wellbore sizes were simulated in order to observe the response of the various rheological models. The simulator allows the input of wellbore and bottom-hole assembly (BHA) sizes, formation properties, drilling parameters, and drilling fluid properties. To assess the hydraulic model's performance during drilling, the user is required to input the drilling parameters based on field data and match the penetration rate. The resulting simulator hydraulic outputs are the equivalent circulation density (ECD) and standpipe pressure (SPP). The simulator's performance was assessed using separate simulations with different rheological models and compared with actual field data. Similarities, differences, and potential improvements were then reported. During the simulation, the most critical drilling parameters are displayed, emulating real-time measured values, combined with the pore pressure, wellbore pressure, and fracture pressure graphs. The simulation results show promise for application of real-time hydraulic operations. The simulated output parameters, ECD and SPP, have similar trends and values with the values from actual field data. The simulator's performance shows excellent matching for a simple BHA, with decreasing system's accuracy as the BHA design becomes more complex, an area of future improvement. The overall approach is valid for non-Newtonian drilling fluid pressure losses. The user can observe the output parameters, and by adding a benchmark safety value, the simulator gives a warning of a potential fracture of the formation or maximum pressure at the mud pumps. Thus, by simulating the drilling process, the user can be trained for the upcoming drilling campaign and reach the target depth safely and cost-effectively during actual drilling. The simulator allows emulation of real-time hydraulic operations when drilling vertical and directional wells, albeit with a simple BHA for the latter. The user can instantly observe the output results, which allows proper action to be taken if necessary. This is a step towards real-time hydraulic operations. The results also indicate that the simulator can be used as an excellent training tool for professionals and students by creating wellbore exercises that can cover different operating scenarios.
{"title":"Application of a Drilling Simulator for Real-Time Drilling Hydraulics Training and Research","authors":"Jelena Skenderija, Alexis Koulidis, V. Kelessidis, Shehab Ahmed","doi":"10.2118/204579-ms","DOIUrl":"https://doi.org/10.2118/204579-ms","url":null,"abstract":"\u0000 Challenging wells require an accurate hydraulic model to achieve maximum performance for drilling applications. This work was conducted with a simulator capable of recreating the actual drilling process, including on-the-fly adjustments of the drilling parameters. The paper focuses on the predictions of the drilling simulator's pressure losses inside the drill string and across the open-hole and casing annuli applying the most common rheological models. Comparison is then made with pressure losses from field data.\u0000 Drilling data of vertical and deviated wells were acquired to recreate the actual drilling environment and wellbore design. Several sections with a variety of wellbore sizes were simulated in order to observe the response of the various rheological models. The simulator allows the input of wellbore and bottom-hole assembly (BHA) sizes, formation properties, drilling parameters, and drilling fluid properties. To assess the hydraulic model's performance during drilling, the user is required to input the drilling parameters based on field data and match the penetration rate. The resulting simulator hydraulic outputs are the equivalent circulation density (ECD) and standpipe pressure (SPP).\u0000 The simulator's performance was assessed using separate simulations with different rheological models and compared with actual field data. Similarities, differences, and potential improvements were then reported. During the simulation, the most critical drilling parameters are displayed, emulating real-time measured values, combined with the pore pressure, wellbore pressure, and fracture pressure graphs. The simulation results show promise for application of real-time hydraulic operations.\u0000 The simulated output parameters, ECD and SPP, have similar trends and values with the values from actual field data. The simulator's performance shows excellent matching for a simple BHA, with decreasing system's accuracy as the BHA design becomes more complex, an area of future improvement.\u0000 The overall approach is valid for non-Newtonian drilling fluid pressure losses. The user can observe the output parameters, and by adding a benchmark safety value, the simulator gives a warning of a potential fracture of the formation or maximum pressure at the mud pumps. Thus, by simulating the drilling process, the user can be trained for the upcoming drilling campaign and reach the target depth safely and cost-effectively during actual drilling.\u0000 The simulator allows emulation of real-time hydraulic operations when drilling vertical and directional wells, albeit with a simple BHA for the latter. The user can instantly observe the output results, which allows proper action to be taken if necessary. This is a step towards real-time hydraulic operations. The results also indicate that the simulator can be used as an excellent training tool for professionals and students by creating wellbore exercises that can cover different operating scenarios.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89890554","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}
We have shown previously that while total porosity is the weighted sum of density and neutron porosities, hydrocarbon volume is the weighted difference of the two. Thus, their ratio yields hydrocarbon, or equivalently, water saturation (Sw). In LWD environments where negligible invasion takes place while drilling, we investigate whether Sw derived from LWD density-neutron logs could approach true Sw in unknown or mixed water salinity environments. In such environments, it is well known that Sw determined from standalone resistivity or capture sigma logs is uncertain due to large water resistivity (Rw) or capture sigma (Σw) changes with salinity. On the other hand, the water density (ρw) and hydrogen index (HIw) variations with salinity are much less (Table 1). Hence, the water point on the density neutron crossplot does not move with salinity as much as the water point on a sigma-porosity crossplot does. Similarly, the water point on a resistivity-porosity Pickett plot would move drastically with changes in Rw. Also, because the hydrocarbon effect on density-neutron logs is much less in oil than in gas, the weights in the density-neutron porosities can be conveniently set at midpoint in light oil-bearing reservoirs without compromising porosity and saturation results. Thus, a quicklook estimate of Sw from density-neutron logs is the normalized ratio of the difference over the sum of density and neutron porosities. The normalization factor is a function of the hydrocarbon density. We also build a graphical Sw overlay for petrophysical insights. We tested the LWD density-neutron derived Sw in two Middle East carbonate oil wells that have mixed salinity. The two wells were extensively studied in the past. In the first well, the reference Sw is given by the joint-inversion of resistivity-sigma logs, corroborated with Sw estimated from multi-measurements time-lapsed analysis, and validated with water analysis on water samples taken by formation testers. In the second well, comprehensive wireline measurements targeting mixed salinity such as dielectric and 3D NMR were acquired to derive Sw, and complemented by formation tester sampling, core measurements, and LWD resistivity-sigma Sw. In both wells, density-neutron quicklook Sw agrees surprisingly well with Sw from other techniques. It may lack the accuracy and precision and the continuous salinity output but is sufficient to pinpoint both flooded zones and bypassed oil zones. Since density-neutron is part of triple-combo data that are first available in well data acquisition, it is recommended to go beyond porosity application and compute water saturation (Sw) in unknown or mixed salinity environments. The computation is straightforward and can be useful to complement other established techniques for quick evaluation in unknown or mixed water salinity environments.
{"title":"Quick-Look Water Saturation Estimate with Density-Neutron Logs in Unknown or Mixed Salinity Environments: Case Studies in Middle East Oil-Bearing Carbonate Reservoirs","authors":"Chanh Cao Minh, Vikas Jain, D. Maggs, K. Gzara","doi":"10.2118/204831-ms","DOIUrl":"https://doi.org/10.2118/204831-ms","url":null,"abstract":"\u0000 We have shown previously that while total porosity is the weighted sum of density and neutron porosities, hydrocarbon volume is the weighted difference of the two. Thus, their ratio yields hydrocarbon, or equivalently, water saturation (Sw). In LWD environments where negligible invasion takes place while drilling, we investigate whether Sw derived from LWD density-neutron logs could approach true Sw in unknown or mixed water salinity environments.\u0000 In such environments, it is well known that Sw determined from standalone resistivity or capture sigma logs is uncertain due to large water resistivity (Rw) or capture sigma (Σw) changes with salinity. On the other hand, the water density (ρw) and hydrogen index (HIw) variations with salinity are much less (Table 1). Hence, the water point on the density neutron crossplot does not move with salinity as much as the water point on a sigma-porosity crossplot does. Similarly, the water point on a resistivity-porosity Pickett plot would move drastically with changes in Rw.\u0000 Also, because the hydrocarbon effect on density-neutron logs is much less in oil than in gas, the weights in the density-neutron porosities can be conveniently set at midpoint in light oil-bearing reservoirs without compromising porosity and saturation results. Thus, a quicklook estimate of Sw from density-neutron logs is the normalized ratio of the difference over the sum of density and neutron porosities. The normalization factor is a function of the hydrocarbon density. We also build a graphical Sw overlay for petrophysical insights.\u0000 We tested the LWD density-neutron derived Sw in two Middle East carbonate oil wells that have mixed salinity. The two wells were extensively studied in the past. In the first well, the reference Sw is given by the joint-inversion of resistivity-sigma logs, corroborated with Sw estimated from multi-measurements time-lapsed analysis, and validated with water analysis on water samples taken by formation testers. In the second well, comprehensive wireline measurements targeting mixed salinity such as dielectric and 3D NMR were acquired to derive Sw, and complemented by formation tester sampling, core measurements, and LWD resistivity-sigma Sw. In both wells, density-neutron quicklook Sw agrees surprisingly well with Sw from other techniques. It may lack the accuracy and precision and the continuous salinity output but is sufficient to pinpoint both flooded zones and bypassed oil zones.\u0000 Since density-neutron is part of triple-combo data that are first available in well data acquisition, it is recommended to go beyond porosity application and compute water saturation (Sw) in unknown or mixed salinity environments. The computation is straightforward and can be useful to complement other established techniques for quick evaluation in unknown or mixed water salinity environments.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89907317","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}
Godwin Chimara, W. Amer, Stephane L'Hostis, Philip Leslie
Minimizing formation damage is vital for maximizing productivity when an openhole (slotted liner) completion strategy is used, and it is particularly challenging in high temperature wells with bottomhole static temperature approaching 190°C (374°F). A barite-weighted fluid system for such high temperature wells was identified as unsuitable due to lack of ability to remediate via acid treatment. This paper discusses how a customized barite-free non-aqueous drill-in fluid system was used to successfully achieve productivity objectives for three such wells. Based on reservoir and well data provided, a 1.15 to 1.20 sg (9.60 to 10.0 lbm/gal) barite-free, non-aqueous drill-in fluid system was designed using a high density calcium chloride/calcium bromide brine as the internal phase to compensate for the absence of barite as a weighting agent. An engineered acid-soluble bridging package was included to protect the reservoir from excess filtrate invasion and allow for potential remediation by acid treatment at a later stage. The fluid system was subjected to formation response testing, and the results obtained proved satisfactory, confirming the fluid system was suited for drilling the reservoir. A similar solids-free system using higher density brine as the internal phase, was also formulated. This was spotted in the open hole once drilling was completed to help eliminate any potential for solids settling before running the slotted liner. Three wells were successfully drilled and completed. The barite-free system remained stable, allowed for trouble-free fluids-handling and drilling operations, and performed as expected. To aid in minimizing fluid invasion into the reservoir, onsite particle size distribution (PSD) measurements were performed in order to optimize bridging material additions while drilling and enhance efficiency in managing the solids control system. Because of the extremely high bottomhole temperature, a mud cooler was installed to help control the flowline temperature below 60°C (140°F); this helped maintain fluid stability and preserve functionality of downhole tools in this hostile environment. The solids-free system was successfully spotted in the open hole after drilling the section before well completion. This eliminated any settling potential and reduced flowback of solids during production. The recorded productivity of these wells met expectations.
{"title":"Barite-Free Non-Aqueous Drill-In Fluid System Maximizes Productivity in High Temperature Wells","authors":"Godwin Chimara, W. Amer, Stephane L'Hostis, Philip Leslie","doi":"10.2118/204826-ms","DOIUrl":"https://doi.org/10.2118/204826-ms","url":null,"abstract":"Minimizing formation damage is vital for maximizing productivity when an openhole (slotted liner) completion strategy is used, and it is particularly challenging in high temperature wells with bottomhole static temperature approaching 190°C (374°F). A barite-weighted fluid system for such high temperature wells was identified as unsuitable due to lack of ability to remediate via acid treatment. This paper discusses how a customized barite-free non-aqueous drill-in fluid system was used to successfully achieve productivity objectives for three such wells. Based on reservoir and well data provided, a 1.15 to 1.20 sg (9.60 to 10.0 lbm/gal) barite-free, non-aqueous drill-in fluid system was designed using a high density calcium chloride/calcium bromide brine as the internal phase to compensate for the absence of barite as a weighting agent. An engineered acid-soluble bridging package was included to protect the reservoir from excess filtrate invasion and allow for potential remediation by acid treatment at a later stage. The fluid system was subjected to formation response testing, and the results obtained proved satisfactory, confirming the fluid system was suited for drilling the reservoir. A similar solids-free system using higher density brine as the internal phase, was also formulated. This was spotted in the open hole once drilling was completed to help eliminate any potential for solids settling before running the slotted liner. Three wells were successfully drilled and completed. The barite-free system remained stable, allowed for trouble-free fluids-handling and drilling operations, and performed as expected. To aid in minimizing fluid invasion into the reservoir, onsite particle size distribution (PSD) measurements were performed in order to optimize bridging material additions while drilling and enhance efficiency in managing the solids control system. Because of the extremely high bottomhole temperature, a mud cooler was installed to help control the flowline temperature below 60°C (140°F); this helped maintain fluid stability and preserve functionality of downhole tools in this hostile environment. The solids-free system was successfully spotted in the open hole after drilling the section before well completion. This eliminated any settling potential and reduced flowback of solids during production. The recorded productivity of these wells met expectations.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76957624","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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