Drilling mud plays a significant role in the drilling operation because it is influential in the quality of the drilled well and the efficiency of the drilling operation. In this paper, we aim to identify the methods to improve the effectiveness of drilling operations by analyzing and evaluating the impact of adding polyacrylamide and a barite/polyacrylamide nanocomposite, synthesized through the solution polymerization method, on the properties of drilling mud. The study added the synthesized nanocomposite to the water-based drilling mud (350 cm3 water with 10 g bentonite) and examined the properties of the drilling mud, including viscosity, fluid loss, and mudcake thickness. Overall, the results indicated that the addition of the synthesized nanocomposite caused a decrease in fluid loss and the thickness of the mudcake, while it increased the drilling mud’s viscosity.
{"title":"Investigating the Properties of Modified Drilling Mud with Barite/Polyacrylamide Nanocomposite","authors":"Pouria Roodbari, S. Sabbaghi","doi":"10.2118/205511-PA","DOIUrl":"https://doi.org/10.2118/205511-PA","url":null,"abstract":"\u0000 Drilling mud plays a significant role in the drilling operation because it is influential in the quality of the drilled well and the efficiency of the drilling operation. In this paper, we aim to identify the methods to improve the effectiveness of drilling operations by analyzing and evaluating the impact of adding polyacrylamide and a barite/polyacrylamide nanocomposite, synthesized through the solution polymerization method, on the properties of drilling mud. The study added the synthesized nanocomposite to the water-based drilling mud (350 cm3 water with 10 g bentonite) and examined the properties of the drilling mud, including viscosity, fluid loss, and mudcake thickness. Overall, the results indicated that the addition of the synthesized nanocomposite caused a decrease in fluid loss and the thickness of the mudcake, while it increased the drilling mud’s viscosity.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-7"},"PeriodicalIF":1.4,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42914845","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Tabatabaei, A. D. Taleghani, Guoqiang Li, Tianyi Zhang
While there have been various lost circulation materials (LCMs) available in the market for treating fractures during the drilling of oil and gas wells, there is still a demand for a technology to seal large fractures. Considering limitations on the size of the particles that can be circulated through the drilling equipment, especially the bottomhole assembly, simply enlarging conventional LCM particles becomes ineffective for sealing large vugs and fractures. In this study, we use shape memory polymers (SMPs) to prepare programmed LCMs with various temporary shapes, which can transform to their permanent shapes with much larger dimensions as compared to their temporary shapes. A series of steps for thermomechanical programming of SMP is designed to trigger their expansion at the reservoir temperature. The dimensions of the programmed shapes can be an order of magnitude smaller than the ones for the original shapes, making their transport through the flowlines feasible, and bridging wide-opened fractures possible. The basic idea is that, after recovery, the SMP-based LCMs form an entangled network across a large width of fracture, and SMP particles recovered within the network, filling in the pores to form an effective sealing. We seek the capability of entangled ladders and interwoven fibers in forming a network across the fracture. A permeability plugging apparatus (PPA) is used to examine the efficiency of developed LCMs. The technique of 3D X-ray computed tomography (CT) is used to visualize the internal structure of formed plugs, enabling us to understand the mechanisms of bridging, plugging, and sealing.
{"title":"Shape Memory Polymers as Lost Circulation Materials for Sealing Wide-Opened Natural Fractures","authors":"M. Tabatabaei, A. D. Taleghani, Guoqiang Li, Tianyi Zhang","doi":"10.2118/205514-PA","DOIUrl":"https://doi.org/10.2118/205514-PA","url":null,"abstract":"\u0000 While there have been various lost circulation materials (LCMs) available in the market for treating fractures during the drilling of oil and gas wells, there is still a demand for a technology to seal large fractures. Considering limitations on the size of the particles that can be circulated through the drilling equipment, especially the bottomhole assembly, simply enlarging conventional LCM particles becomes ineffective for sealing large vugs and fractures. In this study, we use shape memory polymers (SMPs) to prepare programmed LCMs with various temporary shapes, which can transform to their permanent shapes with much larger dimensions as compared to their temporary shapes. A series of steps for thermomechanical programming of SMP is designed to trigger their expansion at the reservoir temperature. The dimensions of the programmed shapes can be an order of magnitude smaller than the ones for the original shapes, making their transport through the flowlines feasible, and bridging wide-opened fractures possible. The basic idea is that, after recovery, the SMP-based LCMs form an entangled network across a large width of fracture, and SMP particles recovered within the network, filling in the pores to form an effective sealing. We seek the capability of entangled ladders and interwoven fibers in forming a network across the fracture. A permeability plugging apparatus (PPA) is used to examine the efficiency of developed LCMs. The technique of 3D X-ray computed tomography (CT) is used to visualize the internal structure of formed plugs, enabling us to understand the mechanisms of bridging, plugging, and sealing.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45052154","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Elastic collapse is an important piece of the tubular collapse formulation in API TR 5C3 (2008) and ISO/TR 10400 (2007). Elastic collapse is significant because it is independent of the strength of the tubing, for example, K-55 and Q-125 have the same resistance to elastic collapse. Advanced collapse models, such as Klever and Tamano (2006), require a thick-wall collapse result as part of their formulation. What would the effect of a thick wall have on elastic collapse? There really is no way to tell from the classic formulation. The primary issue is whether the elastic collapse formula overpredicts or underpredicts collapse pressure. The developers of the API collapse equation thought the thin-wall equation overpredicted collapse pressure and put in terms to reduce the predictions. Other studies suggested the opposite effect. What is needed is a formulation that is based on an elastic solution for a thick-wall cylinder, but that can derive the classic solution for a thin wall. The elastic equations for a thick-walled cylinder exist, known as the Kirsch equations (Kirsch 1898). A new set of physically reasonable boundary conditions are proposed for the Kirsch equation, which was then used to determine the collapse resistance for a thick-wall pipe. This result also yielded the classic result in the limit because t/D is small. The thick-wall elastic collapse formula is then applied to the standard API TR 5C3 (2008) collapse formulation and to the Klever-Tamano formulation (Klever and Tamano 2006).
{"title":"Thick-Wall Elastic Collapse for Casing Design","authors":"R. Mitchell","doi":"10.2118/199677-pa","DOIUrl":"https://doi.org/10.2118/199677-pa","url":null,"abstract":"\u0000 Elastic collapse is an important piece of the tubular collapse formulation in API TR 5C3 (2008) and ISO/TR 10400 (2007). Elastic collapse is significant because it is independent of the strength of the tubing, for example, K-55 and Q-125 have the same resistance to elastic collapse. Advanced collapse models, such as Klever and Tamano (2006), require a thick-wall collapse result as part of their formulation.\u0000 What would the effect of a thick wall have on elastic collapse? There really is no way to tell from the classic formulation. The primary issue is whether the elastic collapse formula overpredicts or underpredicts collapse pressure. The developers of the API collapse equation thought the thin-wall equation overpredicted collapse pressure and put in terms to reduce the predictions. Other studies suggested the opposite effect.\u0000 What is needed is a formulation that is based on an elastic solution for a thick-wall cylinder, but that can derive the classic solution for a thin wall.\u0000 The elastic equations for a thick-walled cylinder exist, known as the Kirsch equations (Kirsch 1898). A new set of physically reasonable boundary conditions are proposed for the Kirsch equation, which was then used to determine the collapse resistance for a thick-wall pipe. This result also yielded the classic result in the limit because t/D is small.\u0000 The thick-wall elastic collapse formula is then applied to the standard API TR 5C3 (2008) collapse formulation and to the Klever-Tamano formulation (Klever and Tamano 2006).","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":""},"PeriodicalIF":1.4,"publicationDate":"2021-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42050688","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.
{"title":"Pressure Decline Analysis in Fractured Horizontal Wells: Comparison between Diagnostic Fracture Injection Test, Flowback, and Main Stage Falloff","authors":"HanYi Wang, Brendan Elliott, M. Sharma","doi":"10.2118/201672-PA","DOIUrl":"https://doi.org/10.2118/201672-PA","url":null,"abstract":"\u0000 The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":"1-13"},"PeriodicalIF":1.4,"publicationDate":"2021-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47722388","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Stephen Adjei, S. Elkatatny, P. Sarmah, Gonzalo Chinea
Fly ash, which is a pozzolan generated as a byproduct from coal-powered plants, is the most used extender in the design of lightweight cement. However, the coal-powered plants are phasing out due to global-warming concerns. There is the need to investigate other materials as substitutes to fly ash. Bentonite is a natural pozzolanic material that is abundant in nature. This pozzolanic property is enhanced upon heat treatment; however, this material has never been explored in oil-well cementing in such form. This study compares the performance of 13-ppg heated (dehydroxylated) sodium bentonite and fly-ash cement systems. The raw (commercial) sodium bentonite was dehydroxylated at 1,526°F for 3 hours. Cement slurries were prepared at 13 ppg using the heated sodium bentonite as partial replacements of cement in concentrations of 10 to 50% by weight of blend. Various tests were done at a bottomhole static temperature of 120°F, bottomhole circulating temperature of 110°F, and pressure of 1,000 psi or atmospheric pressure. All the dehydroxylated sodium bentonite systems exhibited high stability, thickening times in the range of 3 to 5 hours, and a minimum 24-hour compressive strength of 600 psi. At a concentration of 40 and 50%, the 24-hour compressive strength was approximately 800 and 787 psi, respectively. This was higher than a 13-ppg fly-ash-based cement designed at 40% cement replacement (580 psi).
{"title":"Investigation of Dehydroxylated Sodium Bentonite as a Pozzolanic Extender in Oil-Well Cement","authors":"Stephen Adjei, S. Elkatatny, P. Sarmah, Gonzalo Chinea","doi":"10.2118/205487-PA","DOIUrl":"https://doi.org/10.2118/205487-PA","url":null,"abstract":"\u0000 Fly ash, which is a pozzolan generated as a byproduct from coal-powered plants, is the most used extender in the design of lightweight cement. However, the coal-powered plants are phasing out due to global-warming concerns. There is the need to investigate other materials as substitutes to fly ash. Bentonite is a natural pozzolanic material that is abundant in nature. This pozzolanic property is enhanced upon heat treatment; however, this material has never been explored in oil-well cementing in such form. This study compares the performance of 13-ppg heated (dehydroxylated) sodium bentonite and fly-ash cement systems.\u0000 The raw (commercial) sodium bentonite was dehydroxylated at 1,526°F for 3 hours. Cement slurries were prepared at 13 ppg using the heated sodium bentonite as partial replacements of cement in concentrations of 10 to 50% by weight of blend. Various tests were done at a bottomhole static temperature of 120°F, bottomhole circulating temperature of 110°F, and pressure of 1,000 psi or atmospheric pressure.\u0000 All the dehydroxylated sodium bentonite systems exhibited high stability, thickening times in the range of 3 to 5 hours, and a minimum 24-hour compressive strength of 600 psi. At a concentration of 40 and 50%, the 24-hour compressive strength was approximately 800 and 787 psi, respectively. This was higher than a 13-ppg fly-ash-based cement designed at 40% cement replacement (580 psi).","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-8"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46380628","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
As wells in modern operations are getting longer and more complex, assessing the effect of casing wear becomes ever more crucial. Degradation of the tubulars through mechanical wear reduces the pressure capacity significantly. In this paper, we use the finite element method (FEM) to analyze the stress distribution in degraded geometries and to assess reduction in collapse strength. A model for the collapse strength of the casing with a crescent-shaped wear groove is developed and its performance evaluated in relation to experimental data. The model was created by using the Buckingham Pi theorem to make generalized empirical expressions for yield and elastic collapse of tubulars. Finite element analysis (FEA) of 135 geometries was used in the development of the model. The results show that the generalized expressions capture the trends observed in the FEA accurately and match the experimental data from six tubular collapse tests with an average relative difference in collapse pressure of 5.2%.
{"title":"A Generalized Empirical Expression for Collapse of Worn Tubulars Using Stress Concentration Factors","authors":"A. Teigland, B. Brechan, S. Dale, S. Sangesland","doi":"10.2118/205500-PA","DOIUrl":"https://doi.org/10.2118/205500-PA","url":null,"abstract":"\u0000 As wells in modern operations are getting longer and more complex, assessing the effect of casing wear becomes ever more crucial. Degradation of the tubulars through mechanical wear reduces the pressure capacity significantly. In this paper, we use the finite element method (FEM) to analyze the stress distribution in degraded geometries and to assess reduction in collapse strength. A model for the collapse strength of the casing with a crescent-shaped wear groove is developed and its performance evaluated in relation to experimental data. The model was created by using the Buckingham Pi theorem to make generalized empirical expressions for yield and elastic collapse of tubulars. Finite element analysis (FEA) of 135 geometries was used in the development of the model. The results show that the generalized expressions capture the trends observed in the FEA accurately and match the experimental data from six tubular collapse tests with an average relative difference in collapse pressure of 5.2%.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":"1-12"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48728249","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
There is a great deal of interest in the oil and gas industry (OGI) in seeking ways to implement machine learning (ML) to provide valuable insights for increased profitability. With buzzwords such as data analytics, ML, artificial intelligence (AI), and so forth, the curiosity of typical drilling practitioners and researchers is piqued. While a few review papers summarize the application of ML in the OGI, such as Noshi and Schubert (2018), they only provide simple summaries of ML applications without detailed and practical steps that benefit OGI practitioners interested in incorporating ML into their workflow. This paper addresses this gap by systematically reviewing a variety of recent publications to identify the problems posed by oil and gas practitioners and researchers in drilling operations. Analyses are also performed to determine which algorithms are most widely used and in which area of oilwell-drilling operations these algorithms are being used. Deep dives are performed into representative case studies that use ML techniques to address the challenges of oilwell drilling. This study summarizes what ML techniques are used to resolve the challenges faced, and what input parameters are needed for these ML algorithms. The optimal size of the data set necessary is included, and in some cases where to obtain the data set for efficient implementation is also included. Thus, we break down the ML workflow into the three phases commonly used in the input/process/output model. Simplifying the ML applications into this model is expected to help define the appropriate tools to be used for different problems. In this work, data on the required input, appropriate ML method, and the desired output are extracted from representative case studies in the literature of the last decade. The results show that artificial neural networks (ANNs), support vector machines (SVMs), and regression are the most used ML algorithms in drilling, accounting for 18, 17, and 13%, respectively, of all the cases analyzed in this paper. Of the representative case studies, 60% implemented these and other ML techniques to predict the rate of penetration (ROP), differential pipe sticking (DPS), drillstring vibration, or other drilling events. Prediction of rheological properties of drilling fluids and estimation of the formation properties was performed in 22% of the publications reviewed. Some other aspects of drilling in which ML was applied were well planning (5%), pressure management (3%), and well placement (3%). From the results, the top ML algorithms used in the drilling industry are versatile algorithms that are easily applicable in almost any situation. The presentation of the ML workflow in different aspects of drilling is expected to help both drilling practitioners and researchers. Several step-by-step guidelines available in the publications reviewed here will guide the implementation of these algorithms in the resolution of drilling challenges.
{"title":"Practical Machine-Learning Applications in Well-Drilling Operations","authors":"T. Olukoga, Y. Feng","doi":"10.2118/205480-PA","DOIUrl":"https://doi.org/10.2118/205480-PA","url":null,"abstract":"There is a great deal of interest in the oil and gas industry (OGI) in seeking ways to implement machine learning (ML) to provide valuable insights for increased profitability. With buzzwords such as data analytics, ML, artificial intelligence (AI), and so forth, the curiosity of typical drilling practitioners and researchers is piqued. While a few review papers summarize the application of ML in the OGI, such as Noshi and Schubert (2018), they only provide simple summaries of ML applications without detailed and practical steps that benefit OGI practitioners interested in incorporating ML into their workflow. This paper addresses this gap by systematically reviewing a variety of recent publications to identify the problems posed by oil and gas practitioners and researchers in drilling operations. Analyses are also performed to determine which algorithms are most widely used and in which area of oilwell-drilling operations these algorithms are being used. Deep dives are performed into representative case studies that use ML techniques to address the challenges of oilwell drilling. This study summarizes what ML techniques are used to resolve the challenges faced, and what input parameters are needed for these ML algorithms. The optimal size of the data set necessary is included, and in some cases where to obtain the data set for efficient implementation is also included. Thus, we break down the ML workflow into the three phases commonly used in the input/process/output model. Simplifying the ML applications into this model is expected to help define the appropriate tools to be used for different problems. In this work, data on the required input, appropriate ML method, and the desired output are extracted from representative case studies in the literature of the last decade. The results show that artificial neural networks (ANNs), support vector machines (SVMs), and regression are the most used ML algorithms in drilling, accounting for 18, 17, and 13%, respectively, of all the cases analyzed in this paper. Of the representative case studies, 60% implemented these and other ML techniques to predict the rate of penetration (ROP), differential pipe sticking (DPS), drillstring vibration, or other drilling events. Prediction of rheological properties of drilling fluids and estimation of the formation properties was performed in 22% of the publications reviewed. Some other aspects of drilling in which ML was applied were well planning (5%), pressure management (3%), and well placement (3%). From the results, the top ML algorithms used in the drilling industry are versatile algorithms that are easily applicable in almost any situation. The presentation of the ML workflow in different aspects of drilling is expected to help both drilling practitioners and researchers. Several step-by-step guidelines available in the publications reviewed here will guide the implementation of these algorithms in the resolution of drilling challenges.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-19"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46830046","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper we present a methodology to superimpose the American Petroleum Institute (API) uniaxial and triaxial limits on tubular design limits plots (API TR 5C3 2018). Complications caused by a recent change of axis are resolved, producing a practical design limits plot that avoids the horizontal shift of the API vertical limits, which is currently the industry standard. The commonly used slanted ellipse is compared against an adaptation of the circle of plasticity in the form of a horizontal ellipse, showing the convenience of this last one with examples. After the current official collapse formulation was made part of the main body of standard API TR 5C3 (2018), the horizontal axis on the standard industry well tubular design limits plot changed. The present study evaluates this redefinition of the horizontal axis. One consequence of this modification is a difficulty plotting the API tension and compression limits. The API horizontal limits (uniaxial burst and collapse) are found to be independent of load situation, whereas the API vertical design limits (uniaxial tension and compression) are dependent on inside and outside tubular pressures. The approaches used by commercial software and industry publications to solve this challenge are reviewed. A new design methodology is developed to link API uniaxial limits to the triaxial theory. One main objective of the study is to establish a mathematical relationship between API tubular design limits and the von Mises triaxial theory (API TR 5C3 2018). A methodology that allows plotting the API uniaxial force limits on the design limits plot is developed. The study also shows that the results obtained from the industry standard slanted ellipse are identical to those obtained from the horizontal ellipse and circle. One important difference is that the slanted ellipse is based on the zero axial stress datum, whereas the horizontal ellipse/circle uses the neutral axial stress datum. The horizontal ellipse/circle is well suited for calculations involving buckling, compatible with the information used in field operations, and its formulations are less complicated than the tilted ellipse. Therefore, attention is called to the use of the horizontal ellipse/circle in well tubular design.
{"title":"API Equation Design Limits Plot for Ellipse and Circle of Plasticity","authors":"J. Romero, J. Aasen","doi":"10.2118/204079-PA","DOIUrl":"https://doi.org/10.2118/204079-PA","url":null,"abstract":"\u0000 In this paper we present a methodology to superimpose the American Petroleum Institute (API) uniaxial and triaxial limits on tubular design limits plots (API TR 5C3 2018). Complications caused by a recent change of axis are resolved, producing a practical design limits plot that avoids the horizontal shift of the API vertical limits, which is currently the industry standard. The commonly used slanted ellipse is compared against an adaptation of the circle of plasticity in the form of a horizontal ellipse, showing the convenience of this last one with examples.\u0000 After the current official collapse formulation was made part of the main body of standard API TR 5C3 (2018), the horizontal axis on the standard industry well tubular design limits plot changed. The present study evaluates this redefinition of the horizontal axis. One consequence of this modification is a difficulty plotting the API tension and compression limits. The API horizontal limits (uniaxial burst and collapse) are found to be independent of load situation, whereas the API vertical design limits (uniaxial tension and compression) are dependent on inside and outside tubular pressures. The approaches used by commercial software and industry publications to solve this challenge are reviewed. A new design methodology is developed to link API uniaxial limits to the triaxial theory.\u0000 One main objective of the study is to establish a mathematical relationship between API tubular design limits and the von Mises triaxial theory (API TR 5C3 2018). A methodology that allows plotting the API uniaxial force limits on the design limits plot is developed. The study also shows that the results obtained from the industry standard slanted ellipse are identical to those obtained from the horizontal ellipse and circle. One important difference is that the slanted ellipse is based on the zero axial stress datum, whereas the horizontal ellipse/circle uses the neutral axial stress datum. The horizontal ellipse/circle is well suited for calculations involving buckling, compatible with the information used in field operations, and its formulations are less complicated than the tilted ellipse. Therefore, attention is called to the use of the horizontal ellipse/circle in well tubular design.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":" ","pages":"1-12"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45896670","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Elgaddafi, R. Ahmed, H. Karami, M. Nasser, I. Hussein
The accumulation of rock cuttings, proppant, and other solid debris in the wellbore caused by inadequate cleanout remarkably impedes field operations. The cuttings removal process becomes a more challenging task as the coiled-tubing techniques are used during drilling and fracturing operations. This article presents a new hole cleaning model, which calculates the critical transport velocity (CTV) in conventional and fibrous water-based fluids. The study is aimed to establish an accurate mechanistic model for optimizing wellbore cleanout in horizontal and inclined wells. The new CTV model is established to predict the initiation of bed particle movement during cleanout operations. The model is formulated considering the impact of fiber using a special drag coefficient (i.e., fiber drag coefficient), which represents the mechanical and hydrodynamic actions of suspended fiber particles and their network. The dominant forces acting on a single bed particle are considered to develop the model. Furthermore, to enhance the precision of the model, recently developed hydraulic correlations are used to compute the average bed shear stress, which is required to determine the CTV. In horizontal and highly deviated wells, the wellbore geometry is often eccentric, resulting in the formation of flow stagnant zones that are difficult to clean. The bed shear stress in these zones is sensitive to the bed thickness. The existing wellbore cleanout models do not account for the variation in bed shear stress. Thus, their accuracy is limited when stagnant zones are formed. The new model addresses this problem by incorporating hydraulic correlations to account for bed shear stress variation with bed height. The accuracy of the new model is validated with published measurements and compared with the precision of an existing model. The use of fiber drag and bed shear stress correlations has improved model accuracy and aided in capturing the contribution of fiber in improving wellbore cleanout. As a result, for fibrous and conventional water-based fluids, the predictions of the new model have demonstrated good agreement with experimental measurements and provided better predictions than the existing model. Model predictions show a noticeable reduction in fluid circulation rate caused by the addition of a small quantity of fiber (0.04% w/w) in the fluid. In addition, results show that the existing model overpredicts the cleaning performance of both conventional and fibrous water-basedmuds.
{"title":"A Mechanistic Model for Wellbore Cleanout in Horizontal and Inclined Wells","authors":"R. Elgaddafi, R. Ahmed, H. Karami, M. Nasser, I. Hussein","doi":"10.2118/204442-PA","DOIUrl":"https://doi.org/10.2118/204442-PA","url":null,"abstract":"\u0000 The accumulation of rock cuttings, proppant, and other solid debris in the wellbore caused by inadequate cleanout remarkably impedes field operations. The cuttings removal process becomes a more challenging task as the coiled-tubing techniques are used during drilling and fracturing operations. This article presents a new hole cleaning model, which calculates the critical transport velocity (CTV) in conventional and fibrous water-based fluids. The study is aimed to establish an accurate mechanistic model for optimizing wellbore cleanout in horizontal and inclined wells.\u0000 The new CTV model is established to predict the initiation of bed particle movement during cleanout operations. The model is formulated considering the impact of fiber using a special drag coefficient (i.e., fiber drag coefficient), which represents the mechanical and hydrodynamic actions of suspended fiber particles and their network. The dominant forces acting on a single bed particle are considered to develop the model. Furthermore, to enhance the precision of the model, recently developed hydraulic correlations are used to compute the average bed shear stress, which is required to determine the CTV. In horizontal and highly deviated wells, the wellbore geometry is often eccentric, resulting in the formation of flow stagnant zones that are difficult to clean. The bed shear stress in these zones is sensitive to the bed thickness. The existing wellbore cleanout models do not account for the variation in bed shear stress. Thus, their accuracy is limited when stagnant zones are formed. The new model addresses this problem by incorporating hydraulic correlations to account for bed shear stress variation with bed height.\u0000 The accuracy of the new model is validated with published measurements and compared with the precision of an existing model. The use of fiber drag and bed shear stress correlations has improved model accuracy and aided in capturing the contribution of fiber in improving wellbore cleanout. As a result, for fibrous and conventional water-based fluids, the predictions of the new model have demonstrated good agreement with experimental measurements and provided better predictions than the existing model. Model predictions show a noticeable reduction in fluid circulation rate caused by the addition of a small quantity of fiber (0.04% w/w) in the fluid. In addition, results show that the existing model overpredicts the cleaning performance of both conventional and fibrous water-basedmuds.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-17"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44249552","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mohammad Mojammel Huque, S. Imtiaz, S. Zendehboudi, S. Butt, M. A. Rahman, P. Maheshwari
Hole cleaning is a concern in directional and horizontal well drilling operations where drill cuttings tend to settle in the lower annulus section. Laboratory-scale experiments were performed with different non-Newtonian fluids in a 6.16-m-long, 114.3- × 63.5-mm transparent annulus test section to investigate cuttings transport behavior. This experimental study focused on understanding the cuttings transport mechanism in the annulus section with high-speed imaging technology. The movement of cuttings in the inclined annular section was captured with a high-speed camera at 2,000 frames/sec. Also, cuttings bed movement patterns at different fluid velocities and inner pipe rotations were captured with a digital single-lens reflex video camera. The electrical resistance tomography (ERT) system was used to quantify the cuttings volume fraction in the annulus. Different solid bed heights and cuttings movements were observed based on fluid rheology, fluid velocity, and inner pipe rotation. The mechanistic three-layer cuttings transport model was visualized with the experimental procedure. This study showed that solid bed height is significantly reduced with an increase in the inner pipe rotation. This study also identified that cuttings bed thickness largely depends on fluid rheology and wellbore inclination. The image from the high-speed camera identified a downward trend of some rolling particles in the annulus caused by gravitational force at a low mud velocity. Visual observation from a high-speed camera identified a helical motion of solid particles when the drillpipe is in contact with solid particles and rotating at a higher rev/min. Different cuttings movement patterns such as: rolling, sliding, suspension, helical movement, and downward movement were identified from the visualization of a high-speedcamera.
{"title":"Experimental Study of Cuttings Transport with Non-Newtonian Fluid in an Inclined Well Using Visualization and Electrical Resistance Tomography Techniques","authors":"Mohammad Mojammel Huque, S. Imtiaz, S. Zendehboudi, S. Butt, M. A. Rahman, P. Maheshwari","doi":"10.2118/201709-PA","DOIUrl":"https://doi.org/10.2118/201709-PA","url":null,"abstract":"\u0000 Hole cleaning is a concern in directional and horizontal well drilling operations where drill cuttings tend to settle in the lower annulus section. Laboratory-scale experiments were performed with different non-Newtonian fluids in a 6.16-m-long, 114.3- × 63.5-mm transparent annulus test section to investigate cuttings transport behavior. This experimental study focused on understanding the cuttings transport mechanism in the annulus section with high-speed imaging technology. The movement of cuttings in the inclined annular section was captured with a high-speed camera at 2,000 frames/sec. Also, cuttings bed movement patterns at different fluid velocities and inner pipe rotations were captured with a digital single-lens reflex video camera. The electrical resistance tomography (ERT) system was used to quantify the cuttings volume fraction in the annulus. Different solid bed heights and cuttings movements were observed based on fluid rheology, fluid velocity, and inner pipe rotation. The mechanistic three-layer cuttings transport model was visualized with the experimental procedure. This study showed that solid bed height is significantly reduced with an increase in the inner pipe rotation. This study also identified that cuttings bed thickness largely depends on fluid rheology and wellbore inclination. The image from the high-speed camera identified a downward trend of some rolling particles in the annulus caused by gravitational force at a low mud velocity. Visual observation from a high-speed camera identified a helical motion of solid particles when the drillpipe is in contact with solid particles and rotating at a higher rev/min. Different cuttings movement patterns such as: rolling, sliding, suspension, helical movement, and downward movement were identified from the visualization of a high-speedcamera.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":"1 1","pages":"1-18"},"PeriodicalIF":1.4,"publicationDate":"2021-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41968194","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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