A new automated approach to well correlation is presented that utilizes real-time Logging While-Drilling (LWD) data and predicted well curve to dynamically update subsurface layers during geosteering operations. The automatically created predicted log and a dynamically updated structural framework provides the foundation of the process. The predicted log is created using vertical sections of the nearby wells, which provide high confidence for determining depth and stratigraphic position of the geosteered well. The results give a better understanding of thickness variation in the horizontal part of the reservoir and maximize the reservoir contact (Sung, 2008). A new advanced methodology introduced in this study involves the creation of a dynamic structural framework model, from which horizontal well correlation is performed using real-time well logs and predicted logs that are generated from adjacent wells. The predicted logs are correlated to the LWD logs using anchor points and an interactive stretching and squeezing process that honors true stratigraphic thickness. Each new anchor point results in the creation of an additional control point that is used to build a more precise structural framework model. This new approach enables more rapid well log interpretation, increased accuracy and the ability to dynamically update the subsurface model during drilling. It also enables more efficient steering of the wellbore into the most productive zones of the reservoir. This study demonstrates how wells with over 10,000 feet of horizontal reservoir contact can be correlated in a real-time geosteering environment in a dynamic, efficient and accurate manner. The proposed process dramatically helps reduce the cost of drilling and the time it takes to dynamically regenerate accurate updated maps of the subsurface. It represents a major improvement in the understanding and modeling of complex, heterogeneous reservoirs by fostering a multi-disciplinary environment of cross-domain experts that are able to collaborate seamlessly as asset-teams. Both accuracy and efficiency gains have been realized by incorporating this methodology in the characterization of multi-stacked reservoirs.
{"title":"Advanced Horizontal Well Correlation Method for Dynamic Update of Subsurface Layers While Geosteering","authors":"Abdul Mohsen Al-Maskeen, Sadaqat S. Ali","doi":"10.2118/204721-ms","DOIUrl":"https://doi.org/10.2118/204721-ms","url":null,"abstract":"\u0000 A new automated approach to well correlation is presented that utilizes real-time Logging While-Drilling (LWD) data and predicted well curve to dynamically update subsurface layers during geosteering operations. The automatically created predicted log and a dynamically updated structural framework provides the foundation of the process. The predicted log is created using vertical sections of the nearby wells, which provide high confidence for determining depth and stratigraphic position of the geosteered well. The results give a better understanding of thickness variation in the horizontal part of the reservoir and maximize the reservoir contact (Sung, 2008).\u0000 A new advanced methodology introduced in this study involves the creation of a dynamic structural framework model, from which horizontal well correlation is performed using real-time well logs and predicted logs that are generated from adjacent wells. The predicted logs are correlated to the LWD logs using anchor points and an interactive stretching and squeezing process that honors true stratigraphic thickness. Each new anchor point results in the creation of an additional control point that is used to build a more precise structural framework model.\u0000 This new approach enables more rapid well log interpretation, increased accuracy and the ability to dynamically update the subsurface model during drilling. It also enables more efficient steering of the wellbore into the most productive zones of the reservoir. This study demonstrates how wells with over 10,000 feet of horizontal reservoir contact can be correlated in a real-time geosteering environment in a dynamic, efficient and accurate manner. The proposed process dramatically helps reduce the cost of drilling and the time it takes to dynamically regenerate accurate updated maps of the subsurface. It represents a major improvement in the understanding and modeling of complex, heterogeneous reservoirs by fostering a multi-disciplinary environment of cross-domain experts that are able to collaborate seamlessly as asset-teams. Both accuracy and efficiency gains have been realized by incorporating this methodology in the characterization of multi-stacked reservoirs.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89284990","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}
Mohammad Rasheed Khan, S. Kalam, Abdul Asad, Rizwan Ahmed Khan, M. Kamal
Research into the use of polymers for enhanced oil recovery (EOR) processes has been going on for more than 6 decades and is now classified as a techno-commercially viable option. A comprehensive evaluation of the polymer's rheology is pivotal to the success of any polymer EOR process. Laboratory-based evaluation is critical to EOR success; however, it is also a time/capital consuming process. Consequently, any tool which can aid in optimizing lab tests design can bring in great value. Accordingly, in this study a novel predictive correlation for viscosity estimation of commonly used "FP 3330S" EOR polymer is presented through use of cutting-edge machine learning neural networks. Mathematical equation for polymer viscosity is developed using machine learning algorithms as a function of polymer concentration, NaCl concentration, and Ca2+ concentration. The measured input data was collected from the literature and sub-divided into training and test sets. A wide-ranging optimization was performed to select the best parameters for the neural network which includes the number of neurons, neuron layers, activation functions between multiple layers, weights, and bias. Furthermore, the Levenberg-Marquardt back-propagation algorithm was utilized to train the model. Finally, measured and estimated viscosities were compared based on error-analysis. Novel correlation is developed for the polymer that can be used in predictive mode. This established correlation can predict polymer viscosity when applied to the test dataset and outperforms other published models with average error in the range of 3-5% and coefficient of determination in excess of 0.95. Moreover, it is shown that neural networks are faster and relatively better than other machine learning algorithms explored in this study. The proposed correlation can map non-linear relationships between polymer viscosity and other rheological parameters such as molecular weight, polymer concentration, and cation concentration of polymer solution. Lastly, through machine learning validation approach, it was possible to examine feasibility of the proposed models which is not done by traditional empirical equations.
{"title":"Intelligent Predictor for Polymer Viscosity to Enhance Support for EOR Processes","authors":"Mohammad Rasheed Khan, S. Kalam, Abdul Asad, Rizwan Ahmed Khan, M. Kamal","doi":"10.2118/204839-ms","DOIUrl":"https://doi.org/10.2118/204839-ms","url":null,"abstract":"\u0000 Research into the use of polymers for enhanced oil recovery (EOR) processes has been going on for more than 6 decades and is now classified as a techno-commercially viable option. A comprehensive evaluation of the polymer's rheology is pivotal to the success of any polymer EOR process. Laboratory-based evaluation is critical to EOR success; however, it is also a time/capital consuming process. Consequently, any tool which can aid in optimizing lab tests design can bring in great value. Accordingly, in this study a novel predictive correlation for viscosity estimation of commonly used \"FP 3330S\" EOR polymer is presented through use of cutting-edge machine learning neural networks.\u0000 Mathematical equation for polymer viscosity is developed using machine learning algorithms as a function of polymer concentration, NaCl concentration, and Ca2+ concentration. The measured input data was collected from the literature and sub-divided into training and test sets. A wide-ranging optimization was performed to select the best parameters for the neural network which includes the number of neurons, neuron layers, activation functions between multiple layers, weights, and bias. Furthermore, the Levenberg-Marquardt back-propagation algorithm was utilized to train the model. Finally, measured and estimated viscosities were compared based on error-analysis.\u0000 Novel correlation is developed for the polymer that can be used in predictive mode. This established correlation can predict polymer viscosity when applied to the test dataset and outperforms other published models with average error in the range of 3-5% and coefficient of determination in excess of 0.95. Moreover, it is shown that neural networks are faster and relatively better than other machine learning algorithms explored in this study. The proposed correlation can map non-linear relationships between polymer viscosity and other rheological parameters such as molecular weight, polymer concentration, and cation concentration of polymer solution. Lastly, through machine learning validation approach, it was possible to examine feasibility of the proposed models which is not done by traditional empirical equations.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85755596","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}
U. Prasad, A. Hanif, I. McGlynn, F. Walles, A. Abouzaid, O. Hamid
The influences of mineralogy on rock mechanical properties have profound application in oil and gas exploration and production processes, including hydraulic fracturing operations. In conventional resources, the rock mechanical properties are predominantly controlled by porosity; however, in unconventional tight formations, the importance of mineralogy as a function of rock mechanical properties has not been fully investigated. In unconventional tight formations, mechanical properties are often derived from mineralogy weight fraction together with the best estimate of porosity, assumption of fluid types, the extent of pore fillings, and fluid properties. These properties are then adjusted for their volumetric fractions and subsequently calibrated with acoustics or geomechanical lab measurements. A new method is presented that utilizes mineralogy weight fractions (determined from well logs or laboratory measurements). This process uses public domain information of minerals using Voigt and Reuss averaging algorithms as upper and lower bounds, respectively. An average of these bounds (also known as Hill average) provides a representative value for these parameters. Further, based on isotropic conditions, all the elastic properties are calculated. A typical output consisting of bulk-, shear-, and Young's - modulus, together with Poisson's ratio obtained from traditional methods of volume fractions and this new method using weight fractions is discussed and analyzed along with the sensitivity and the trends for individual rock properties. Furthermore, corresponding strengths, hardness, and fracture toughness could also be estimated using well known public domain algorithms. Data from carbonate reservoirs has been discussed in this work. This method shows how to estimate grain compressibility that can be challenging to be measured in the lab for unconventional tight rock samples. In low-porosity samples, the relative influence of porosity is negligible compared to the mineralogy composition. This approach reduces several assumptions and uncertainties associated with accurate porosity determination in tight rocks as it does not require the amount of pore fluids and fluid properties in calculations. The grain-compressibility and bulk-compressibility (measured by hydrostatic tests in the laboratory on core plugs or calculated from density and cross-dipole log) are used to calculate poroelastic Biot's coefficient, as this coefficient will be used to calculate in-situ principal effective stresses (overburden, minimum horizontal, and maximum horizontal stresses), which are, together with rock properties and pore pressure, constitutes the geomechanical model. The geomechanical model is used for drilling, completions, and hydraulic fracture modeling, including wellbore stability, and reservoir integrity analyses.
{"title":"An Innovative Methodology for Estimating Rock Mechanical Properties from Weight or Volume Fractions of Mineralogy and its Application to Middle East Reservoirs","authors":"U. Prasad, A. Hanif, I. McGlynn, F. Walles, A. Abouzaid, O. Hamid","doi":"10.2118/204687-ms","DOIUrl":"https://doi.org/10.2118/204687-ms","url":null,"abstract":"\u0000 The influences of mineralogy on rock mechanical properties have profound application in oil and gas exploration and production processes, including hydraulic fracturing operations. In conventional resources, the rock mechanical properties are predominantly controlled by porosity; however, in unconventional tight formations, the importance of mineralogy as a function of rock mechanical properties has not been fully investigated.\u0000 In unconventional tight formations, mechanical properties are often derived from mineralogy weight fraction together with the best estimate of porosity, assumption of fluid types, the extent of pore fillings, and fluid properties. These properties are then adjusted for their volumetric fractions and subsequently calibrated with acoustics or geomechanical lab measurements. A new method is presented that utilizes mineralogy weight fractions (determined from well logs or laboratory measurements). This process uses public domain information of minerals using Voigt and Reuss averaging algorithms as upper and lower bounds, respectively. An average of these bounds (also known as Hill average) provides a representative value for these parameters. Further, based on isotropic conditions, all the elastic properties are calculated.\u0000 A typical output consisting of bulk-, shear-, and Young's - modulus, together with Poisson's ratio obtained from traditional methods of volume fractions and this new method using weight fractions is discussed and analyzed along with the sensitivity and the trends for individual rock properties. Furthermore, corresponding strengths, hardness, and fracture toughness could also be estimated using well known public domain algorithms.\u0000 Data from carbonate reservoirs has been discussed in this work. This method shows how to estimate grain compressibility that can be challenging to be measured in the lab for unconventional tight rock samples. In low-porosity samples, the relative influence of porosity is negligible compared to the mineralogy composition. This approach reduces several assumptions and uncertainties associated with accurate porosity determination in tight rocks as it does not require the amount of pore fluids and fluid properties in calculations. The grain-compressibility and bulk-compressibility (measured by hydrostatic tests in the laboratory on core plugs or calculated from density and cross-dipole log) are used to calculate poroelastic Biot's coefficient, as this coefficient will be used to calculate in-situ principal effective stresses (overburden, minimum horizontal, and maximum horizontal stresses), which are, together with rock properties and pore pressure, constitutes the geomechanical model. The geomechanical model is used for drilling, completions, and hydraulic fracture modeling, including wellbore stability, and reservoir integrity analyses.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87288757","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}
D. Salim, M. Thiel, Beate Nesttun Øyen, Kong Bakti Tan, J. Denichou, Vera Krissetiawati Wibowo, Desheng Zhang, K. Harms, M. Etchebes, F. Antonsen, Maria Emilia De Oliveira
The successful drilling of horizontal wells targeting reservoir zones of interest can be challenged by uncertainties in geological interpretation, identification of structure, and properties of reservoirs and fluid distribution. Optimizing the well placement of high-angle wells in order to intercept the sweet spots is crucial for the total hydrocarbon recovery in any development field. Thus, the geosteering domain was implemented to provide in real time a reservoir mapping characterization together with directional control to achieve the key performance objectives. In the past, many innovative technologies have been introduced in geosteering discipline, among them lately the deep EM directional resistivity tool that provides 1D formation resistivity mapping while drilling. However, despite the fact of delivering a multilayer mapping of the reservoir structure up to tens of meters away from wellbore, the real-time interpretation can be limited by this type of inversion. Since it is a 1D approach, these inversions map resistive boundaries on the vertical axis and assume infinite extend in all other directions. Consequently, in a complex geological setting, 1D approximation may fall short of properly describing the reservoir structure. This communication describes how the introduction of the 2D azimuthal resistivity inversions while drilling was conducted and details the various innovations required in the domains of downhole logging while drilling (LWD) measurements transmission in addition to adaptation of inversion methodology for real-time deployment, mainly through the use of high-performance cloud computing. The final enablement was the execution of automated workflows to process and deliver these advanced inversions into an integrated 3D geomodelling software within the turnaround time of drilling operations. This novel technology provides, while drilling, a better understanding of the 3D geological environment and fluid distribution with a deep depth of investigation, as well as the required information to make support for geosteering decisions for optimal well positioning. Initial field deployments were successfully conducted in horizontal wells, and three examples are presented here. Those real cases, executed with wire-drilled-pipe or mud-pulse telemetries, demonstrated the benefits of integrating 2D azimuthal inversions into the current geosteering workflow to provide a complete 3D structural understanding of the reservoir while drilling. This communication documents in detail how such an approach led to operational efficiency improvements in the form of 3D reservoir mapping in real-time, supporting a strategic change in the original well to turn toward the sweet spot, which was located sideways from the planned trajectory.
{"title":"High Performance Computing on the Cloud Successfully Deployed for 3D Geosteering and Reservoir Mapping While Drilling","authors":"D. Salim, M. Thiel, Beate Nesttun Øyen, Kong Bakti Tan, J. Denichou, Vera Krissetiawati Wibowo, Desheng Zhang, K. Harms, M. Etchebes, F. Antonsen, Maria Emilia De Oliveira","doi":"10.2118/204828-ms","DOIUrl":"https://doi.org/10.2118/204828-ms","url":null,"abstract":"\u0000 The successful drilling of horizontal wells targeting reservoir zones of interest can be challenged by uncertainties in geological interpretation, identification of structure, and properties of reservoirs and fluid distribution. Optimizing the well placement of high-angle wells in order to intercept the sweet spots is crucial for the total hydrocarbon recovery in any development field. Thus, the geosteering domain was implemented to provide in real time a reservoir mapping characterization together with directional control to achieve the key performance objectives. In the past, many innovative technologies have been introduced in geosteering discipline, among them lately the deep EM directional resistivity tool that provides 1D formation resistivity mapping while drilling.\u0000 However, despite the fact of delivering a multilayer mapping of the reservoir structure up to tens of meters away from wellbore, the real-time interpretation can be limited by this type of inversion. Since it is a 1D approach, these inversions map resistive boundaries on the vertical axis and assume infinite extend in all other directions. Consequently, in a complex geological setting, 1D approximation may fall short of properly describing the reservoir structure.\u0000 This communication describes how the introduction of the 2D azimuthal resistivity inversions while drilling was conducted and details the various innovations required in the domains of downhole logging while drilling (LWD) measurements transmission in addition to adaptation of inversion methodology for real-time deployment, mainly through the use of high-performance cloud computing. The final enablement was the execution of automated workflows to process and deliver these advanced inversions into an integrated 3D geomodelling software within the turnaround time of drilling operations.\u0000 This novel technology provides, while drilling, a better understanding of the 3D geological environment and fluid distribution with a deep depth of investigation, as well as the required information to make support for geosteering decisions for optimal well positioning. Initial field deployments were successfully conducted in horizontal wells, and three examples are presented here. Those real cases, executed with wire-drilled-pipe or mud-pulse telemetries, demonstrated the benefits of integrating 2D azimuthal inversions into the current geosteering workflow to provide a complete 3D structural understanding of the reservoir while drilling. This communication documents in detail how such an approach led to operational efficiency improvements in the form of 3D reservoir mapping in real-time, supporting a strategic change in the original well to turn toward the sweet spot, which was located sideways from the planned trajectory.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86773176","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}
Enrique Villarroel, G. Chochua, Alex Garro, A. Gnanavelu
Hydraulic fracturing is a well stimulation treatment that has been around since the 1940s, becoming more popular in recent years because of the unconventional hydraulic fracturing boom in North America. Between the 1990s and 2000s, the oil and gas industry found an effective way to extract hydrocarbons from formations that were previously uneconomical to produce. Consolidated unconventional formations such as shale and other tight rocks can now be artificially fractured to induce connectivity among the pores containing hydrocarbons, enabling them to easily flow into the wellbore for recovery at the surface. The method of fracturing unconventional reservoirs requires a large amount of surface equipment, continuously working to stimulate the multiple stages perforated along the horizontal section of the shale formation. The operations normally happen on a single or multi-wells pad with several sets of perforations fractured by using the zipper-fracturing methodology (Sierra & Mayerhofer, 2014). Compared with conventional hydraulic fracturing, the surface equipment must perform for extended pump time periods with only short stops for maintenance and replacement of damaged components. This paper addresses improvements made to the fracturing fluid delivery systems as an alternative to the fracturing iron traditionally used in fracture stimulation services. The improvement aims to enhance equipment reliability and simplify surface setup while reducing surface friction pressure during the hydraulic fracturing treatment.
{"title":"High-Pressure Flexible Pipe for Fracturing Fluid Delivery","authors":"Enrique Villarroel, G. Chochua, Alex Garro, A. Gnanavelu","doi":"10.2118/204530-ms","DOIUrl":"https://doi.org/10.2118/204530-ms","url":null,"abstract":"\u0000 Hydraulic fracturing is a well stimulation treatment that has been around since the 1940s, becoming more popular in recent years because of the unconventional hydraulic fracturing boom in North America.\u0000 Between the 1990s and 2000s, the oil and gas industry found an effective way to extract hydrocarbons from formations that were previously uneconomical to produce. Consolidated unconventional formations such as shale and other tight rocks can now be artificially fractured to induce connectivity among the pores containing hydrocarbons, enabling them to easily flow into the wellbore for recovery at the surface.\u0000 The method of fracturing unconventional reservoirs requires a large amount of surface equipment, continuously working to stimulate the multiple stages perforated along the horizontal section of the shale formation. The operations normally happen on a single or multi-wells pad with several sets of perforations fractured by using the zipper-fracturing methodology (Sierra & Mayerhofer, 2014). Compared with conventional hydraulic fracturing, the surface equipment must perform for extended pump time periods with only short stops for maintenance and replacement of damaged components.\u0000 This paper addresses improvements made to the fracturing fluid delivery systems as an alternative to the fracturing iron traditionally used in fracture stimulation services. The improvement aims to enhance equipment reliability and simplify surface setup while reducing surface friction pressure during the hydraulic fracturing treatment.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84145009","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}
Employers commonly use time-consuming screening tools or online matching engines that are driven by manual roles and predefined keywords, to search for potential job applicants. Such traditional techniques have not kept pace with the new digital revolution in machine learning and big data analytics. This paper presents advanced artificial intelligent solutions employed for ranking resumes and CV-to-Job Description matching. Open source resumes and job descriptions' documents were used to construct and validate the machine learning models in this paper. Documents were converted to images and processed via Google cloud using Optical Character Recognition algorithm (OCR) to extract text information from all resumes and job descriptions' documents, with more than 97% accuracy. Prior to modeling, the extracted text were processed via a series of Natural Language Processing (NLP) techniques by splitting/tokenizing common words, grouping together inflected form of words, i.e. lemmatization, and removal of stop words and punctuation marks. After text processing, resumes were trained using the unsupervised machine learning algorithm, Latent Dirichlet Allocation (LDA), for topic modeling and categorization. Given the type of resumes used, the algorithm was able to categorize them into 4 main job sectors: marketing and business, engineering, computer science/IT and health. Scores were assigned to each resume to represent the maximum LDA probability for ranking. Another more advanced deep learning algorithm, called Doc2Vec, was also used to train and match potential resumes to relevant job descriptions. In this model, resumes are represented by unique vectors that can be used to group similar documents, match and retrieve resumes related to a given job description document provided by HR. The similarity is measured between each resume and the given job description file to query the top job candidates. The model was tested against several job description files related to engineering, IT and human resources, and was able to identify the top-ranking resumes from over hundreds of trained resumes. This paper presents an innovative method for processing, categorizing and ranking resumes using advanced computational models empowered by the latest fourth industrial resolution technologies. This solution is beneficial to both job seekers and employers, providing efficient and unbiased data-driven method for finding top applicants for a given job.
{"title":"Talent Acquisition Process Optimization Using Machine Learning in Resumes’ Ranking and Matching to Job Descriptions","authors":"Mohammed Alghazal","doi":"10.2118/204534-ms","DOIUrl":"https://doi.org/10.2118/204534-ms","url":null,"abstract":"\u0000 Employers commonly use time-consuming screening tools or online matching engines that are driven by manual roles and predefined keywords, to search for potential job applicants. Such traditional techniques have not kept pace with the new digital revolution in machine learning and big data analytics. This paper presents advanced artificial intelligent solutions employed for ranking resumes and CV-to-Job Description matching.\u0000 Open source resumes and job descriptions' documents were used to construct and validate the machine learning models in this paper. Documents were converted to images and processed via Google cloud using Optical Character Recognition algorithm (OCR) to extract text information from all resumes and job descriptions' documents, with more than 97% accuracy. Prior to modeling, the extracted text were processed via a series of Natural Language Processing (NLP) techniques by splitting/tokenizing common words, grouping together inflected form of words, i.e. lemmatization, and removal of stop words and punctuation marks.\u0000 After text processing, resumes were trained using the unsupervised machine learning algorithm, Latent Dirichlet Allocation (LDA), for topic modeling and categorization. Given the type of resumes used, the algorithm was able to categorize them into 4 main job sectors: marketing and business, engineering, computer science/IT and health. Scores were assigned to each resume to represent the maximum LDA probability for ranking. Another more advanced deep learning algorithm, called Doc2Vec, was also used to train and match potential resumes to relevant job descriptions. In this model, resumes are represented by unique vectors that can be used to group similar documents, match and retrieve resumes related to a given job description document provided by HR. The similarity is measured between each resume and the given job description file to query the top job candidates. The model was tested against several job description files related to engineering, IT and human resources, and was able to identify the top-ranking resumes from over hundreds of trained resumes.\u0000 This paper presents an innovative method for processing, categorizing and ranking resumes using advanced computational models empowered by the latest fourth industrial resolution technologies. This solution is beneficial to both job seekers and employers, providing efficient and unbiased data-driven method for finding top applicants for a given job.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82600456","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
During the evolution of the petroleum industry, surface seismic imaging has played a critical role in reservoir characterization. In the early days, borehole seismic (BHS) was developed to complement surface seismic. However, in the last few decades, a wide range of BHS surveys has been introduced to cater to new and unique objectives over the oilfield lifecycle. In the exploration phase, vertical seismic profiling (VSP) provides critical time-depth information to bridge time indexed subsurface images to log/reservoir properties in depth. This information can be obtained using several methods like conventional wireline checkshot or zero-offset vertical seismic profiling (ZVSP), seismic while drilling (SWD) or distributed acoustic sensing (DAS) techniques. SWD is a relatively new technique to record real-time data using tool deployed in the bottomhole assembly without disturbing the drilling. It helps to improve decision making for safer drilling especially in new areas in a cost-effective manner. Recently, a breakthrough technology, distributed acoustic sensing (DAS), has been introduced, where data are recorded using a fiber-optic cable with lots of saving. ZVSP also provides several parameters like, attenuation coefficient (Q), multiples prediction, impedance, reflectivity etc., which helps with characterizing the subsurface and seismic reprocessing. In the appraisal phase, BHS applications vary from velocity model update, anisotropy estimation, well- tie to imaging VSPs. The three-component VSP data is best suited for imaging and amplitude variation with offset (AVO) due to several factors like less noise interference due to quiet downhole environment, higher frequency bandwidth, proximity to the reflector, etc. Different type of VSP surveys (offset, walkaway, walkaround etc.) were designed to fulfill objectives like imaging, AVO, Q, anisotropy, and fracture mapping. In the development phase, high-resolution images (3D VSP, walkaway, or crosswell) from BHS surveys can assist with optimizing the drilling of new wells and, hence reduce costs. it can help with landing point selection, horizontal section placement, and refining interpretation for reserve calculation. BHS offers a wide range of surveys to assist the oilfield lifecycle during the production phase. Microseismic monitoring is an industry-known service to optimize hydraulic fracturing and is the only technique that captures the induced seismicity generated by hydraulic fracturing and estimate the fracture geometry (height, width, and azimuth) and in real time. During enhanced oil recovery (EOR) projects, BHS can be useful to optimize the hydrocarbon drainage strategies by mapping the fluid movement (CO2, water, steam) using time-lapse surveys like walkaway, 3D VSP and/or crosswell. DAS has brought a new dimension to provide vital information on injection or production evaluation, leak detection, flow behind tubing, crossflow diagnosis, and cement evaluation during production phas
{"title":"Borehole Seismic: Essential Contributions Over the Oilfield Lifecycle","authors":"Rajeev Kumar, P. Bettinelli","doi":"10.2118/204889-ms","DOIUrl":"https://doi.org/10.2118/204889-ms","url":null,"abstract":"\u0000 During the evolution of the petroleum industry, surface seismic imaging has played a critical role in reservoir characterization. In the early days, borehole seismic (BHS) was developed to complement surface seismic. However, in the last few decades, a wide range of BHS surveys has been introduced to cater to new and unique objectives over the oilfield lifecycle.\u0000 In the exploration phase, vertical seismic profiling (VSP) provides critical time-depth information to bridge time indexed subsurface images to log/reservoir properties in depth. This information can be obtained using several methods like conventional wireline checkshot or zero-offset vertical seismic profiling (ZVSP), seismic while drilling (SWD) or distributed acoustic sensing (DAS) techniques. SWD is a relatively new technique to record real-time data using tool deployed in the bottomhole assembly without disturbing the drilling. It helps to improve decision making for safer drilling especially in new areas in a cost-effective manner. Recently, a breakthrough technology, distributed acoustic sensing (DAS), has been introduced, where data are recorded using a fiber-optic cable with lots of saving. ZVSP also provides several parameters like, attenuation coefficient (Q), multiples prediction, impedance, reflectivity etc., which helps with characterizing the subsurface and seismic reprocessing.\u0000 In the appraisal phase, BHS applications vary from velocity model update, anisotropy estimation, well- tie to imaging VSPs. The three-component VSP data is best suited for imaging and amplitude variation with offset (AVO) due to several factors like less noise interference due to quiet downhole environment, higher frequency bandwidth, proximity to the reflector, etc. Different type of VSP surveys (offset, walkaway, walkaround etc.) were designed to fulfill objectives like imaging, AVO, Q, anisotropy, and fracture mapping.\u0000 In the development phase, high-resolution images (3D VSP, walkaway, or crosswell) from BHS surveys can assist with optimizing the drilling of new wells and, hence reduce costs. it can help with landing point selection, horizontal section placement, and refining interpretation for reserve calculation.\u0000 BHS offers a wide range of surveys to assist the oilfield lifecycle during the production phase. Microseismic monitoring is an industry-known service to optimize hydraulic fracturing and is the only technique that captures the induced seismicity generated by hydraulic fracturing and estimate the fracture geometry (height, width, and azimuth) and in real time. During enhanced oil recovery (EOR) projects, BHS can be useful to optimize the hydrocarbon drainage strategies by mapping the fluid movement (CO2, water, steam) using time-lapse surveys like walkaway, 3D VSP and/or crosswell. DAS has brought a new dimension to provide vital information on injection or production evaluation, leak detection, flow behind tubing, crossflow diagnosis, and cement evaluation during production phas","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87552063","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}
Dissolvable tools have been used more in unconventional oil and gas operations in recent years. Sealing element is one of the important parts of the dissolvable tools. The dissolvable rubbers in the market either have low strength or the dissolution rate was low. A series of high strength dissolvable rubbers with various dissolution rate have been developed by CNPC-USA to meet the industrial requirements. The mechanical properties of the dissolvable rubbers were tested at ambient and high temperatures. The dissolvable rubber coupons were soaked in water, 0.3%, 1% KCl at 80, 90 and 120 °C for various durations up to 47 days. The mass, dimensions, volume, hardness, density, and tensile properties of the samples were measured after different durations to characterize the dissolution rate. In addition, the pressure rating of dissolvable rubber sealing element was tested in water environment at 90 °C or 100 °C and in oil environment at 120 °C for 24 hours. The dissolution rate of the dissolvable rubber sealing element was tested at 90 °C or 80 °C in brine. It was found that the tensile strength of the dissolvable rubber at high temperature was in the range of 800-3000 psi and the elongation of the dissolvable rubber at high temperature was higher than 500%, which was higher than that of the most of the commercial dissolvable rubbers. For 90-120°C rated dissolvable rubbers, the dissolvable rubber coupons were disintegrated in brine at 90 °C in 5-15 days and the dissolvable rubber was completely dissolved in brine at 120°C in 4 days. The dissolvable rubber sealing elements hold 10,000 psi pressure differential at 90 °C in water and at 120 °C in oil environment for more than 24 hours. On the other hand, the dissolvable rubber sealing element were disintegrated in 90°C, 1% KCl in 7-11 days. For 80-120°C rated dissolvable rubbers, the dissolvable rubber coupons were disintegrated in brine at 80°C in 3-10 days. The dissolvable rubber sealing elements hold 8,700 psi pressure differential for 24 hours and 10,000 psi pressure differential at 100 °C for 15 minutes. On the other hand, the dissolvable rubber sealing elements were disintegrated at 80°C in 1% KCl in 3-5 days. The pressure rating properties and dissolution rate properties of the dissolvable rubber sealing elements met the field operation requirements. The dissolvable plugs with the dissolvable rubber sealing elements have been successfully used in multiple tight-oil wells and more than 15 shale gas wells fracturing operations in China. The dissolution rate of the dissolvable rubber could be controlled by adjusting the formulations. The dissolution rate of the dissolvable rubber was independent of brine concentration. CNPC-USA has developed a series of dissolvable rubbers in the temperature range from 40°C to 175°C applications to meet different operation requirements.
{"title":"Dissolvable Rubbers Development and its Applications in Downhole Tools","authors":"Jiaxiang Ren, Pengyu Cheng, Xu Wang","doi":"10.2118/204622-ms","DOIUrl":"https://doi.org/10.2118/204622-ms","url":null,"abstract":"\u0000 Dissolvable tools have been used more in unconventional oil and gas operations in recent years. Sealing element is one of the important parts of the dissolvable tools. The dissolvable rubbers in the market either have low strength or the dissolution rate was low. A series of high strength dissolvable rubbers with various dissolution rate have been developed by CNPC-USA to meet the industrial requirements.\u0000 The mechanical properties of the dissolvable rubbers were tested at ambient and high temperatures. The dissolvable rubber coupons were soaked in water, 0.3%, 1% KCl at 80, 90 and 120 °C for various durations up to 47 days. The mass, dimensions, volume, hardness, density, and tensile properties of the samples were measured after different durations to characterize the dissolution rate. In addition, the pressure rating of dissolvable rubber sealing element was tested in water environment at 90 °C or 100 °C and in oil environment at 120 °C for 24 hours. The dissolution rate of the dissolvable rubber sealing element was tested at 90 °C or 80 °C in brine. It was found that the tensile strength of the dissolvable rubber at high temperature was in the range of 800-3000 psi and the elongation of the dissolvable rubber at high temperature was higher than 500%, which was higher than that of the most of the commercial dissolvable rubbers.\u0000 For 90-120°C rated dissolvable rubbers, the dissolvable rubber coupons were disintegrated in brine at 90 °C in 5-15 days and the dissolvable rubber was completely dissolved in brine at 120°C in 4 days. The dissolvable rubber sealing elements hold 10,000 psi pressure differential at 90 °C in water and at 120 °C in oil environment for more than 24 hours. On the other hand, the dissolvable rubber sealing element were disintegrated in 90°C, 1% KCl in 7-11 days.\u0000 For 80-120°C rated dissolvable rubbers, the dissolvable rubber coupons were disintegrated in brine at 80°C in 3-10 days. The dissolvable rubber sealing elements hold 8,700 psi pressure differential for 24 hours and 10,000 psi pressure differential at 100 °C for 15 minutes. On the other hand, the dissolvable rubber sealing elements were disintegrated at 80°C in 1% KCl in 3-5 days.\u0000 The pressure rating properties and dissolution rate properties of the dissolvable rubber sealing elements met the field operation requirements. The dissolvable plugs with the dissolvable rubber sealing elements have been successfully used in multiple tight-oil wells and more than 15 shale gas wells fracturing operations in China.\u0000 The dissolution rate of the dissolvable rubber could be controlled by adjusting the formulations. The dissolution rate of the dissolvable rubber was independent of brine concentration. CNPC-USA has developed a series of dissolvable rubbers in the temperature range from 40°C to 175°C applications to meet different operation requirements.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86213044","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}
Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved. Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of "plugging large pore and leave the small one open", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed. Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced. Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.
{"title":"Study on the Oil Displacement Effect and Application of Soft Microgel Flooding Technology","authors":"Jian Zhang, Zhe Sun, Xiujun Wang, Xiaodong Kang","doi":"10.2118/204764-ms","DOIUrl":"https://doi.org/10.2118/204764-ms","url":null,"abstract":"\u0000 Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved.\u0000 Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of \"plugging large pore and leave the small one open\", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed.\u0000 Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced.\u0000 Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76989428","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}
Muneer Al Noumani, Younis Al Masoudi, M.M. Al Mamari, Yaqdhan Khalfan Al Rawahi, Mohammed Al Yaarubi, Safa Al Nabhani, I. Cameron, David Knox, Roberto Peralta, Emmanuel Thérond
For many years, the oil and gas industry has deployed techniques which enhance formation strength via the successful propping and plugging of induced fractures. Induced fracture sizes have been successfully treated using this method up to the 600 – 1,100-micron range. Static wellbore strengthening techniques are commonly deployed to cover 1,000 micron and all fracture size risks underneath. The deployment of wellbore strengthening techniques has historically been confined to permeable formations. In most cases, wellbore strengthening has been deployed to operationally challenging sand fracture gradients or, where boundaries are pushed, lower ranges of permeability, such as silts. The subject of wellbore strengthening in shales or carbonates to this day, remains a challenge for the industry, with very few documented success stories or evidence of sustained ability to enhance fracture gradient across a drilling campaign. This paper covers the history of lost circulation events which have been reported in the Khazzan/Ghazeer field in the carbonate Habshan formation. It also describes the design changes which were introduced to strengthen the rock and enable circulation/returns, during liner cementation. The design work built on experience applying wellbore strengthening techniques in carbonates in the Norwegian sector of the North Sea. This work is also summarized in this paper. The Habshan carbonate formation in Oman presents a lost circulation challenge through an ‘induced’ fracture risk. Since the beginning of the drilling campaign in the Khazzan/Ghazeer field, the Habshan formation has repeatedly experienced induced mud losses during well activities such as liner running, mud conditioning with liner on bottom and cementing, when the formation is exposed to higher pressures, less so during drilling. The Habshan challenge in Oman has led to regular, significant lost circulation events during cement placement, adding operational cost and more importantly, presenting difficulties around meeting zonal isolation objectives. Through previous field experience in Norway, a set of criteria was developed to qualify a standard pill approach to carbonate strengthening. The currently deployed strategy is designed to address both the risk of induced fracture by propping and plugging (wellbore strengthening) and provide some ability to seal natural fractures which are often encountered with carbonates, or similarly flawed rocks. The strategy deployed aims to cover these two risks with a blanket approach to lost circulation risk in carbonates. The success of this approach is demonstrated using well performance data from a total of 43 wells drilled before and after the introduction of the wellbore strengthening strategy. As it was initially assumed that wellbore strengthening could not be applied to carbonate formations, other techniques had been tried to prevent lost circulation. Those techniques provided mixed results. Since the implementation of wellb
{"title":"Application of Wellbore Strengthening Techniques in Carbonate Formation Solves Lost Circulation Challenges During Liner Running and Cementing","authors":"Muneer Al Noumani, Younis Al Masoudi, M.M. Al Mamari, Yaqdhan Khalfan Al Rawahi, Mohammed Al Yaarubi, Safa Al Nabhani, I. Cameron, David Knox, Roberto Peralta, Emmanuel Thérond","doi":"10.2118/204594-ms","DOIUrl":"https://doi.org/10.2118/204594-ms","url":null,"abstract":"\u0000 For many years, the oil and gas industry has deployed techniques which enhance formation strength via the successful propping and plugging of induced fractures. Induced fracture sizes have been successfully treated using this method up to the 600 – 1,100-micron range. Static wellbore strengthening techniques are commonly deployed to cover 1,000 micron and all fracture size risks underneath.\u0000 The deployment of wellbore strengthening techniques has historically been confined to permeable formations. In most cases, wellbore strengthening has been deployed to operationally challenging sand fracture gradients or, where boundaries are pushed, lower ranges of permeability, such as silts. The subject of wellbore strengthening in shales or carbonates to this day, remains a challenge for the industry, with very few documented success stories or evidence of sustained ability to enhance fracture gradient across a drilling campaign.\u0000 This paper covers the history of lost circulation events which have been reported in the Khazzan/Ghazeer field in the carbonate Habshan formation. It also describes the design changes which were introduced to strengthen the rock and enable circulation/returns, during liner cementation. The design work built on experience applying wellbore strengthening techniques in carbonates in the Norwegian sector of the North Sea. This work is also summarized in this paper.\u0000 The Habshan carbonate formation in Oman presents a lost circulation challenge through an ‘induced’ fracture risk. Since the beginning of the drilling campaign in the Khazzan/Ghazeer field, the Habshan formation has repeatedly experienced induced mud losses during well activities such as liner running, mud conditioning with liner on bottom and cementing, when the formation is exposed to higher pressures, less so during drilling. The Habshan challenge in Oman has led to regular, significant lost circulation events during cement placement, adding operational cost and more importantly, presenting difficulties around meeting zonal isolation objectives.\u0000 Through previous field experience in Norway, a set of criteria was developed to qualify a standard pill approach to carbonate strengthening. The currently deployed strategy is designed to address both the risk of induced fracture by propping and plugging (wellbore strengthening) and provide some ability to seal natural fractures which are often encountered with carbonates, or similarly flawed rocks. The strategy deployed aims to cover these two risks with a blanket approach to lost circulation risk in carbonates.\u0000 The success of this approach is demonstrated using well performance data from a total of 43 wells drilled before and after the introduction of the wellbore strengthening strategy.\u0000 As it was initially assumed that wellbore strengthening could not be applied to carbonate formations, other techniques had been tried to prevent lost circulation. Those techniques provided mixed results.\u0000 Since the implementation of wellb","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78533750","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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