Y. S. Pereira, Raphael Pereira Scudino Borges, E. Schnitzler, Roger Savoldi Roman, Henrique Von Paraski, Alice Claussen Destri, João Almeida Destri, Danilo Signorini Gozzi, C. Baumann, Carlos Merino
Some completion operation steps, such as perforation and packer seating, require that the degree of uncertainty be limited. The main correlation methods used today are based on tally accuracy, tagging a known element in the well or using wireline gamma ray readings. This paper discusses the development of four alternative depth correlation techniques that aim at avoiding the use of wireline in completion and well testing scenarios. All these methods were implemented in field jobs and demonstrated their efficiency with lower operational cost, higher operational safety and acceptable margin of error for the target job. Two methods are based on gamma ray readings and to send data to surface they use logging while drilling (LWD) and wireless telemetry. Target applications for these two methods are tubing-conveyed perforation (TCP) and well testing operations. The other two methods use casing internal diameter (ID) changes at known depths to determine string depth. One uses a rigid hole-opener to tag a crossover or the top of a liner and the other uses the pressure drop produced by a packer entering into a well section with smaller ID. The main advantages of these new depth correlation techniques are rig time savings and greater operational safety by reducing personnel exposure to dangerous operations.
{"title":"New Strategies for Cost Reduction with Depth Correlation in Deepwater Wells","authors":"Y. S. Pereira, Raphael Pereira Scudino Borges, E. Schnitzler, Roger Savoldi Roman, Henrique Von Paraski, Alice Claussen Destri, João Almeida Destri, Danilo Signorini Gozzi, C. Baumann, Carlos Merino","doi":"10.4043/29842-ms","DOIUrl":"https://doi.org/10.4043/29842-ms","url":null,"abstract":"\u0000 Some completion operation steps, such as perforation and packer seating, require that the degree of uncertainty be limited. The main correlation methods used today are based on tally accuracy, tagging a known element in the well or using wireline gamma ray readings. This paper discusses the development of four alternative depth correlation techniques that aim at avoiding the use of wireline in completion and well testing scenarios. All these methods were implemented in field jobs and demonstrated their efficiency with lower operational cost, higher operational safety and acceptable margin of error for the target job. Two methods are based on gamma ray readings and to send data to surface they use logging while drilling (LWD) and wireless telemetry. Target applications for these two methods are tubing-conveyed perforation (TCP) and well testing operations. The other two methods use casing internal diameter (ID) changes at known depths to determine string depth. One uses a rigid hole-opener to tag a crossover or the top of a liner and the other uses the pressure drop produced by a packer entering into a well section with smaller ID. The main advantages of these new depth correlation techniques are rig time savings and greater operational safety by reducing personnel exposure to dangerous operations.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124055662","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}
B. Cornelissen, H. Knoester, M. Breed, Marco Schipper
Fiber reinforced thermoplastic pipes (RTPs) are increasingly used for the transportation of oil and gas. This paper is on the development of special RTPs for the transportation of high pressure hydrogen gas. Production of hydrogen fuel is an attractive way to store renewable energy, and cope with increasing demand and supply needs to adapt renewables. Renewable energy generation like wind and solar with combined hydrogen production requires future offshore and onshore hydrogen transport. We demonstrate the applicability of aramid reinforced thermoplastic pipes for hydrogen transport. We predict the dimensional stability of RTPs in general with an analytical model. The capability of para-aramid reinforced thermoplastic pipes is investigated both conceptually and theoretically. This paper shows the versatility of fiber reinforced pipes and their potential use in decarbonized energy systems. We built a simple analytical model facilitating the design process of RTPs. The model predicts how design parameters like pipe diameter, fiber layer thickness, orientation and amount of reinforcement per unit pipe length affect the deformation of the pipe under a given pressure. Accurately predicting the lifetime of RTPs is one of the main challenges. The analytical model rigorously translates pipe loading into yarn stresses and strains and is therefore a useful tool to understand pipe failure in terms of the yarn's long-term properties. The model provides an easy and fast understanding of the mechanics of RTPs, without requiring the complexity of, for instance, FEM calculations.
{"title":"Aramid Reinforced Thermoplastic Pipes RTPs for Transport of Hydrogen Gas","authors":"B. Cornelissen, H. Knoester, M. Breed, Marco Schipper","doi":"10.4043/29756-ms","DOIUrl":"https://doi.org/10.4043/29756-ms","url":null,"abstract":"\u0000 Fiber reinforced thermoplastic pipes (RTPs) are increasingly used for the transportation of oil and gas. This paper is on the development of special RTPs for the transportation of high pressure hydrogen gas. Production of hydrogen fuel is an attractive way to store renewable energy, and cope with increasing demand and supply needs to adapt renewables. Renewable energy generation like wind and solar with combined hydrogen production requires future offshore and onshore hydrogen transport. We demonstrate the applicability of aramid reinforced thermoplastic pipes for hydrogen transport. We predict the dimensional stability of RTPs in general with an analytical model.\u0000 The capability of para-aramid reinforced thermoplastic pipes is investigated both conceptually and theoretically. This paper shows the versatility of fiber reinforced pipes and their potential use in decarbonized energy systems. We built a simple analytical model facilitating the design process of RTPs. The model predicts how design parameters like pipe diameter, fiber layer thickness, orientation and amount of reinforcement per unit pipe length affect the deformation of the pipe under a given pressure. Accurately predicting the lifetime of RTPs is one of the main challenges. The analytical model rigorously translates pipe loading into yarn stresses and strains and is therefore a useful tool to understand pipe failure in terms of the yarn's long-term properties. The model provides an easy and fast understanding of the mechanics of RTPs, without requiring the complexity of, for instance, FEM calculations.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124186603","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}
Alexandre Campos Manhaes, Aloysio Garcia Neto, A. A. Zanetti, Daniel Tiago Muller, E. Radespiel, Leonardo Marazzo Garcia
Dealing with well integrity non-compliances with respect to the principle of two well barrier envelopes is a problem of paramount importance in well integrity governance during the life cycle of wells. Besides, during production phase, operators might experience several difficulties related to the feasibility and conclusiveness of well integrity assessments, this is especially true for subsea wells. On the other hand, those assessments are quite conclusive and easy to perform by the rig when a workover is in progress. Namely, because there is usually only one fluid phase (brine) during pressure test and the feasibility of performing those tests in the actual flow direction, the well barrier elements evaluations performed by the workover rig are, in general, conclusive when compared to the verifications done by the production platform during production phase. Thus, it is common to find out some unforeseen well integrity non-compliances with respect to the principle of two well barrier envelopes during a workover. Therefore the operator must establish a process for making up a decision concerning whether the handover process after the intervention back to the production team or downhole plugging the well whenever it is necessary, depending upon the well integrity status. This decision is based upon a preemptive (preventive and anticipative) risk assessment. The use of a preemptive risk assessment leads to very interesting results, namely: a) standardization of decision making process avoiding subjectivities about well integrity statuses evaluation; b) savings on applying highly skilled technical human resources; c) mitigating environmental and compliance problems; and d) guidance on workover designers with better intervention planning practices concerning well integrity uncertainties. This paper describes how it can be done as well as the regulations aspects related to it. Furthermore, it is shown case studies to illustrate the whole process of making up the right decision of handing the well over or downhole plugging whenever it is needed.
{"title":"Granting Operating Permit Based Upon a Preemptive Risk Assessment","authors":"Alexandre Campos Manhaes, Aloysio Garcia Neto, A. A. Zanetti, Daniel Tiago Muller, E. Radespiel, Leonardo Marazzo Garcia","doi":"10.4043/29703-ms","DOIUrl":"https://doi.org/10.4043/29703-ms","url":null,"abstract":"\u0000 Dealing with well integrity non-compliances with respect to the principle of two well barrier envelopes is a problem of paramount importance in well integrity governance during the life cycle of wells. Besides, during production phase, operators might experience several difficulties related to the feasibility and conclusiveness of well integrity assessments, this is especially true for subsea wells. On the other hand, those assessments are quite conclusive and easy to perform by the rig when a workover is in progress. Namely, because there is usually only one fluid phase (brine) during pressure test and the feasibility of performing those tests in the actual flow direction, the well barrier elements evaluations performed by the workover rig are, in general, conclusive when compared to the verifications done by the production platform during production phase.\u0000 Thus, it is common to find out some unforeseen well integrity non-compliances with respect to the principle of two well barrier envelopes during a workover. Therefore the operator must establish a process for making up a decision concerning whether the handover process after the intervention back to the production team or downhole plugging the well whenever it is necessary, depending upon the well integrity status. This decision is based upon a preemptive (preventive and anticipative) risk assessment.\u0000 The use of a preemptive risk assessment leads to very interesting results, namely: a) standardization of decision making process avoiding subjectivities about well integrity statuses evaluation; b) savings on applying highly skilled technical human resources; c) mitigating environmental and compliance problems; and d) guidance on workover designers with better intervention planning practices concerning well integrity uncertainties.\u0000 This paper describes how it can be done as well as the regulations aspects related to it. Furthermore, it is shown case studies to illustrate the whole process of making up the right decision of handing the well over or downhole plugging whenever it is needed.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127664829","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}
A. C. S. Mota, V. Barbosa, F. G. Friaça, M. S. Pereira, C. Ataíde
With the increasing severity of environmental legislation, the disposal of drill cuttings has become a critical issue. Once the solids control system reaches contaminant contents close to the established limit value, alternative treatment technologies have been studied, such as microwave drying. In this scope, dielectric properties of two distinct cuttings, one obtained from clay formations and the other from reservoir, were measured in different conditions. It could be inferred from the results that the cuttings are absorbent materials and the loss tangent is directly proportional to their contaminant content. Additionally, a predictive kinetic model previously designed for clay cuttings was tested for reservoir cuttings, showing that the model is also aplicable in the analysis of the drying behavior of reservoir cuttings for low values of applied power. It was concluded that the insertion of dielectric parameters into the kinetic models enabled not only yield prediction, but also provided a better understanding of how the selected materials behave under different microwave process conditions, both qualitatively and quantitatively. It is important to highlight that this knowledge on microwave drying is fundamental not only to the optimization and control of the process, but also to the development of new technologies that make use of specific characteristics of the phenomena.
{"title":"The Importance of Dielectric Properties for the Optimization of Microwave Drying Systems in the Treatment of Drill Cuttings","authors":"A. C. S. Mota, V. Barbosa, F. G. Friaça, M. S. Pereira, C. Ataíde","doi":"10.4043/29922-ms","DOIUrl":"https://doi.org/10.4043/29922-ms","url":null,"abstract":"\u0000 With the increasing severity of environmental legislation, the disposal of drill cuttings has become a critical issue. Once the solids control system reaches contaminant contents close to the established limit value, alternative treatment technologies have been studied, such as microwave drying. In this scope, dielectric properties of two distinct cuttings, one obtained from clay formations and the other from reservoir, were measured in different conditions. It could be inferred from the results that the cuttings are absorbent materials and the loss tangent is directly proportional to their contaminant content. Additionally, a predictive kinetic model previously designed for clay cuttings was tested for reservoir cuttings, showing that the model is also aplicable in the analysis of the drying behavior of reservoir cuttings for low values of applied power. It was concluded that the insertion of dielectric parameters into the kinetic models enabled not only yield prediction, but also provided a better understanding of how the selected materials behave under different microwave process conditions, both qualitatively and quantitatively. It is important to highlight that this knowledge on microwave drying is fundamental not only to the optimization and control of the process, but also to the development of new technologies that make use of specific characteristics of the phenomena.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"89 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128632022","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}
Nikoo Golshahi, S. Afra, H. Samouei, H. Nasr-El-Din, Lia Beraldo da Silveira Balestrin
Asphaltenes precipitation during carbon dioxide injection to enhance recovery has been considered as one of the major challenges in the tertiary production phase. How CO2 would change the asphaltenes structure is still unknown. The present study investigates the effects of CO2 on the isolated asphaltenes by means of various analytical techniques. Chemical structure of precipitated asphaltenes in the presence and absence of CO2 were characterized and compared. These results were coupled with the results of the stability assessment to determine the effects of structural alteration on asphaltenes stability in the oil matrix. Four different crude oils were used to implement this experiment. In the first step, asphaltenes were precipitated by n-heptane. The asphaltenes were then dissolved in toluene and CO2 was injected (at 870 psi) to these solutions and they were mixed at 752°F. This process was repeated for three days, and one week to identify the effect of time on the possible reaction between CO2 and asphaltenes at elevated temperature and pressure. Next, CO2 was injected to the crude oils to determine whether it would react with other components of the oils other than asphaltenes. Same procedures were repeated with nitrogen as controlling experiments. For characterization, Fourier Transform Infrared Spectroscopy (FTIR spectroscopy) was conducted to specify the functional groups and their changes due to the addition of CO2. Finally, stability alteration of precipitated asphaltenes after reaction with CO2 was evaluated by UV-Vis spectroscopy. FTIR results analyses demonstrated that in one tested sample the peak related to the amide functional group is created after injecting CO2. This peak was intensified by increasing the reaction time. To characterize the origin and mechanism of amide formation, 1,4-diazabicyclo[2.2.2]octane (DABCO) was added to this asphaltenes sample during reaction with CO2. Neither escalation of carbonyl group nor generation of aldehyde functional group was detected in the presence of DABCO. Such an observation proves that the amide group was formed by the reaction of amine in the asphaltenes and CO2. The stability of this sample in model oil was decreased after reaction with CO2. On the contrary, FTIR spectrums of the other three samples were not altered after reaction with CO2. Interestingly, one of these three asphaltenes samples became unstable in the model oil after reaction with CO2. This study shows that the asphaltenes instability in the presence of CO2 could be a consequence of either chemical structural alteration of asphaltenes or change of the oil matrix solubility. Hence a comprehensive characterization of an oil sample is essential before designing any CO2 injection treatment. Accordingly, these results can be utilized to select more efficient inhibitors and stabilizers to prevent asphaltenes precipitation.
{"title":"Asphaltene Structural Changes Induced by Carbon Dioxide Injection","authors":"Nikoo Golshahi, S. Afra, H. Samouei, H. Nasr-El-Din, Lia Beraldo da Silveira Balestrin","doi":"10.4043/29730-ms","DOIUrl":"https://doi.org/10.4043/29730-ms","url":null,"abstract":"\u0000 Asphaltenes precipitation during carbon dioxide injection to enhance recovery has been considered as one of the major challenges in the tertiary production phase. How CO2 would change the asphaltenes structure is still unknown. The present study investigates the effects of CO2 on the isolated asphaltenes by means of various analytical techniques. Chemical structure of precipitated asphaltenes in the presence and absence of CO2 were characterized and compared. These results were coupled with the results of the stability assessment to determine the effects of structural alteration on asphaltenes stability in the oil matrix.\u0000 Four different crude oils were used to implement this experiment. In the first step, asphaltenes were precipitated by n-heptane. The asphaltenes were then dissolved in toluene and CO2 was injected (at 870 psi) to these solutions and they were mixed at 752°F. This process was repeated for three days, and one week to identify the effect of time on the possible reaction between CO2 and asphaltenes at elevated temperature and pressure. Next, CO2 was injected to the crude oils to determine whether it would react with other components of the oils other than asphaltenes. Same procedures were repeated with nitrogen as controlling experiments. For characterization, Fourier Transform Infrared Spectroscopy (FTIR spectroscopy) was conducted to specify the functional groups and their changes due to the addition of CO2. Finally, stability alteration of precipitated asphaltenes after reaction with CO2 was evaluated by UV-Vis spectroscopy.\u0000 FTIR results analyses demonstrated that in one tested sample the peak related to the amide functional group is created after injecting CO2. This peak was intensified by increasing the reaction time. To characterize the origin and mechanism of amide formation, 1,4-diazabicyclo[2.2.2]octane (DABCO) was added to this asphaltenes sample during reaction with CO2. Neither escalation of carbonyl group nor generation of aldehyde functional group was detected in the presence of DABCO. Such an observation proves that the amide group was formed by the reaction of amine in the asphaltenes and CO2. The stability of this sample in model oil was decreased after reaction with CO2. On the contrary, FTIR spectrums of the other three samples were not altered after reaction with CO2. Interestingly, one of these three asphaltenes samples became unstable in the model oil after reaction with CO2.\u0000 This study shows that the asphaltenes instability in the presence of CO2 could be a consequence of either chemical structural alteration of asphaltenes or change of the oil matrix solubility. Hence a comprehensive characterization of an oil sample is essential before designing any CO2 injection treatment. Accordingly, these results can be utilized to select more efficient inhibitors and stabilizers to prevent asphaltenes precipitation.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"147 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124415339","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}
A major cause of remedial operations from production liner cementing is not achieving isolation from reservoir to surface. Occurrences increase in wells with inclinations of approximately 90° and necessitate isolating areas close to the liner overlap because of the difficulty reaching satisfactory standoff of the liner in relation to the wellbore or poor mud conditioning before the cement operation. During cement slurry displacement, a preferred circulation path for the cement slurry may cause poor or even nonexistent isolation. An even greater challenge is remediating this type of failure, because leakages at the top of liners may have extremely low injectivity. Conventional remediation systems, such as Class G cement slurries, are often ineffective because of the high concentration of solids present within these systems. Applying an epoxy resin (a solids-free system) combined with best practices of plug positioning to restore well integrity was achieved on the first attempt, ending 45 days of nonproductive time (NPT) for a deepwater operator.
{"title":"Epoxy Resin Ends 45 Days of Nonproductive Time in Deepwater Wells: Case History","authors":"R. Blanc, L. Brunherotto","doi":"10.4043/29915-ms","DOIUrl":"https://doi.org/10.4043/29915-ms","url":null,"abstract":"\u0000 A major cause of remedial operations from production liner cementing is not achieving isolation from reservoir to surface. Occurrences increase in wells with inclinations of approximately 90° and necessitate isolating areas close to the liner overlap because of the difficulty reaching satisfactory standoff of the liner in relation to the wellbore or poor mud conditioning before the cement operation. During cement slurry displacement, a preferred circulation path for the cement slurry may cause poor or even nonexistent isolation. An even greater challenge is remediating this type of failure, because leakages at the top of liners may have extremely low injectivity. Conventional remediation systems, such as Class G cement slurries, are often ineffective because of the high concentration of solids present within these systems. Applying an epoxy resin (a solids-free system) combined with best practices of plug positioning to restore well integrity was achieved on the first attempt, ending 45 days of nonproductive time (NPT) for a deepwater operator.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128787685","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a digitization process that utilizes laser scanning techniques as the design basis for a process plant web-based 3D navigable model. The solution is based on gathering a points cloud from the digitalized plant using the LiDAR surveying method, also commomly called 3D laser scanning, that measures the distance to target by illuminating the target with a pulsed laser light and measure the reflected light by a probe. The digital 3D model is assembled made from the laser return time and wavelength. Each scene is catalogued into a database and further presented into an interactive model of an industrial plant. 3D scanning techniques had been utilized in the Manufacturing and Construction businesses thoroughly and it has been proven very efficient. Constructability of like-for-like replacements and/or new installations, along with computer-based analysis of interreferences with millimetric dimensional verifications, are some of the most usual benefits. The WebScan-360 approach introduces a new portfolio of benefits where the conversion of the gathered scenes into construction drawings are faster, less prone to human error and a precise replica of the reality, especially when compared with the normal surveying method. Documents generation are quicker, more reliable and reduce exponentially the time for information gathering on existing documentation. Construction workpacks development and plant familiarization are much easily to be done, helpin in shutdown/campaign planning. Reduing the risks of misinterpretation and improves the communication across the involved teams with an easy and interactive reference. The novelty of the WebScan-360 application lies in the interaction of a solid and precise engineering database to create efficients and quicker outputs for the entire industrial plants maintenance and modifications business.
{"title":"A New Maintenance Era with Digitalization","authors":"Paulo Ramos Ribas, A. Barbosa, C. Coutinho","doi":"10.4043/29808-ms","DOIUrl":"https://doi.org/10.4043/29808-ms","url":null,"abstract":"\u0000 This paper presents a digitization process that utilizes laser scanning techniques as the design basis for a process plant web-based 3D navigable model.\u0000 The solution is based on gathering a points cloud from the digitalized plant using the LiDAR surveying method, also commomly called 3D laser scanning, that measures the distance to target by illuminating the target with a pulsed laser light and measure the reflected light by a probe. The digital 3D model is assembled made from the laser return time and wavelength. Each scene is catalogued into a database and further presented into an interactive model of an industrial plant.\u0000 3D scanning techniques had been utilized in the Manufacturing and Construction businesses thoroughly and it has been proven very efficient. Constructability of like-for-like replacements and/or new installations, along with computer-based analysis of interreferences with millimetric dimensional verifications, are some of the most usual benefits. The WebScan-360 approach introduces a new portfolio of benefits where the conversion of the gathered scenes into construction drawings are faster, less prone to human error and a precise replica of the reality, especially when compared with the normal surveying method. Documents generation are quicker, more reliable and reduce exponentially the time for information gathering on existing documentation. Construction workpacks development and plant familiarization are much easily to be done, helpin in shutdown/campaign planning. Reduing the risks of misinterpretation and improves the communication across the involved teams with an easy and interactive reference.\u0000 The novelty of the WebScan-360 application lies in the interaction of a solid and precise engineering database to create efficients and quicker outputs for the entire industrial plants maintenance and modifications business.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"100 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130694082","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}
Exploratory and appraisal drilling in extensive salt intervals poses a severe challenge in terms of nonproductive time (NPT) and associated costs. This paper introduces the concept of the mechanical specific energy (MSE) index for creep control in real time. This index is fundamental to leveraging an understanding of MSE behavior while drilling and managing an effective equivalent circulating density (ECD) plan. An ECD management plan must be restricted to a salt creep operational window (SCOW) between a lower limit and a higher ECD limit. The higher limit is based on a leakoff test (LOT) or formation integrity test (FIT). The challenge in defining a SCOW is therefore assessing the lower limit because its variations with depth determine the minimum ECD. A retrospective analysis of a Brazilian presalt exploration campaign determined that, while drilling in salt layers, a direct relationship exists between creep effects (caused by insufficient ECD to stabilize the wellbore) and the behavior of applied MSE (MSEa) with depth. This relationship was analyzed to create an MSE index as a probability vs. depth matrix to help estimate the lower ECD limit during predrill planning and to make necessary adjustments to operational parameters while drilling. This paper presents two salt creep control cases in the Brazilian pre-salt. In the first case, drilling occurred in an extremely soluble salt environment with a high tendency to creep and cause stuck pipe. Geomechanical analysis in real time helped to control creep in the entire drilled salt interval. This analysis resulted in exceptional performance in a critically important section by eliminating five of the ten planned operational days and managing ECD within the predicted SCOW by a good safety margin. Conversely, situations occur in both thin post-salt depositional environments and large shallow and evaporitic sections in which the SCOW does not permit creep control with a good safety margin. The second case presents specific solutions for this complex scenario, which is characterized by low LOTs/FITs, causing lost circulation and stuck pipe. In response, the authors propose that the industry adopt a new concept, the MSE index, to support the SCOW design in predrill planning and real-time operations. The aim of this paper is to help reduce operational days, drilling risks, and costs in drilling environments with complex geopressure variations and narrow pore pressure windows by providing techniques to maintain pressure control, reduce NPT, decrease the potential for mud losses, and reduce stuck pipe events.
{"title":"MSE-Index: A New Concept of Energy Management to Control Salt Creep and Optimize Drilling Operations in Extensive Salt Intervals","authors":"C. N. Pinto, Angelo P Lima, S. Knabe","doi":"10.4043/29795-ms","DOIUrl":"https://doi.org/10.4043/29795-ms","url":null,"abstract":"\u0000 Exploratory and appraisal drilling in extensive salt intervals poses a severe challenge in terms of nonproductive time (NPT) and associated costs. This paper introduces the concept of the mechanical specific energy (MSE) index for creep control in real time. This index is fundamental to leveraging an understanding of MSE behavior while drilling and managing an effective equivalent circulating density (ECD) plan.\u0000 An ECD management plan must be restricted to a salt creep operational window (SCOW) between a lower limit and a higher ECD limit. The higher limit is based on a leakoff test (LOT) or formation integrity test (FIT). The challenge in defining a SCOW is therefore assessing the lower limit because its variations with depth determine the minimum ECD. A retrospective analysis of a Brazilian presalt exploration campaign determined that, while drilling in salt layers, a direct relationship exists between creep effects (caused by insufficient ECD to stabilize the wellbore) and the behavior of applied MSE (MSEa) with depth. This relationship was analyzed to create an MSE index as a probability vs. depth matrix to help estimate the lower ECD limit during predrill planning and to make necessary adjustments to operational parameters while drilling.\u0000 This paper presents two salt creep control cases in the Brazilian pre-salt.\u0000 In the first case, drilling occurred in an extremely soluble salt environment with a high tendency to creep and cause stuck pipe. Geomechanical analysis in real time helped to control creep in the entire drilled salt interval. This analysis resulted in exceptional performance in a critically important section by eliminating five of the ten planned operational days and managing ECD within the predicted SCOW by a good safety margin.\u0000 Conversely, situations occur in both thin post-salt depositional environments and large shallow and evaporitic sections in which the SCOW does not permit creep control with a good safety margin. The second case presents specific solutions for this complex scenario, which is characterized by low LOTs/FITs, causing lost circulation and stuck pipe. In response, the authors propose that the industry adopt a new concept, the MSE index, to support the SCOW design in predrill planning and real-time operations.\u0000 The aim of this paper is to help reduce operational days, drilling risks, and costs in drilling environments with complex geopressure variations and narrow pore pressure windows by providing techniques to maintain pressure control, reduce NPT, decrease the potential for mud losses, and reduce stuck pipe events.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"123 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133673596","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The plans to develop the ASA BRANCA OFFSHORE WINDPOWER PROJECT were envisioned a long time ago, by 2001, after a great drought in Brazil, as reported in the Historical Scenario of this article, aiming at providing the National Grid with larger clean energy sources by means of offshore wind power plants. Its initial phase shall start by 2025 with 720 MW of installed capacity on the Brazilian Northeast coast. Today, it represents a challenging project since its implementation will be the largest pioneer offshore generation not only in Brazil, but also in the southern hemisphere at the tropical environment near the equator. The feasibility studies indicate the higher capacity factor of this Project that accrues from the known trade winds on this region blowing steadily toward the equator from the southeast. The Project presented herein shall be the first phase of a much larger Offshore Wind Farm development that EÓLICA BRASIL has defined and presented to the Brazilian Authorities. This Phase-I has received permits to be installed at the sea near shore in the Municipality of Amontada, in an area that spans 15 km along the coast of Ceará State and at about 9 to 18 km distance of from the seashore. In this region, there are more than 6 GW of onshore wind power plants installed or planed along the coasts of the Northeast Region at Ceará and Rio Grande do Norte States, distributed in hundreds of small and medium onshore generations very near the seashore. The successful operational experience of those projects is a significant indication of the unexplored offshore windpower potential available on this Brazilian coastal region, so that it is included among the most promising regions in the world to produce bulk clean power, especially considering huge offshore windpower plants that will certainly be one of the main Brazilian contributions to reduce the risks from global warming. World's biggest companies, from hi-tech firms to large banks, are bracing for prospect that climate change could substantially affect their bottom lines yet within the next decade due to impacts that will be faced as the planet warms. Early estimates suggest that trillions of dollars may ultimately be at stake. The development of such enormous offshore potential of renewable energy, assured by existing both Brazilian legislation and official regulations, became technical and economic feasible in Brazil by applying the new conception of offshore wind turbine generators (WTGs) with unit ratings larger than 10 MW propelled by wind speeds faster than 10m/sec. This paper presents the main technical characteristics of the conceptual design of this pioneer Project in Brazil, including the basics of planning and feasibility studies as well as the foreseen scenarios for national power market for offshore wind generation on the horizon of the next decade (2021-2030).
{"title":"Asa Branca Offshore Wind Farm Project – Main Technical Aspects","authors":"A. Wey","doi":"10.4043/29838-ms","DOIUrl":"https://doi.org/10.4043/29838-ms","url":null,"abstract":"\u0000 The plans to develop the ASA BRANCA OFFSHORE WINDPOWER PROJECT were envisioned a long time ago, by 2001, after a great drought in Brazil, as reported in the Historical Scenario of this article, aiming at providing the National Grid with larger clean energy sources by means of offshore wind power plants. Its initial phase shall start by 2025 with 720 MW of installed capacity on the Brazilian Northeast coast. Today, it represents a challenging project since its implementation will be the largest pioneer offshore generation not only in Brazil, but also in the southern hemisphere at the tropical environment near the equator. The feasibility studies indicate the higher capacity factor of this Project that accrues from the known trade winds on this region blowing steadily toward the equator from the southeast.\u0000 The Project presented herein shall be the first phase of a much larger Offshore Wind Farm development that EÓLICA BRASIL has defined and presented to the Brazilian Authorities. This Phase-I has received permits to be installed at the sea near shore in the Municipality of Amontada, in an area that spans 15 km along the coast of Ceará State and at about 9 to 18 km distance of from the seashore.\u0000 In this region, there are more than 6 GW of onshore wind power plants installed or planed along the coasts of the Northeast Region at Ceará and Rio Grande do Norte States, distributed in hundreds of small and medium onshore generations very near the seashore. The successful operational experience of those projects is a significant indication of the unexplored offshore windpower potential available on this Brazilian coastal region, so that it is included among the most promising regions in the world to produce bulk clean power, especially considering huge offshore windpower plants that will certainly be one of the main Brazilian contributions to reduce the risks from global warming. World's biggest companies, from hi-tech firms to large banks, are bracing for prospect that climate change could substantially affect their bottom lines yet within the next decade due to impacts that will be faced as the planet warms. Early estimates suggest that trillions of dollars may ultimately be at stake.\u0000 The development of such enormous offshore potential of renewable energy, assured by existing both Brazilian legislation and official regulations, became technical and economic feasible in Brazil by applying the new conception of offshore wind turbine generators (WTGs) with unit ratings larger than 10 MW propelled by wind speeds faster than 10m/sec.\u0000 This paper presents the main technical characteristics of the conceptual design of this pioneer Project in Brazil, including the basics of planning and feasibility studies as well as the foreseen scenarios for national power market for offshore wind generation on the horizon of the next decade (2021-2030).","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"258 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116192748","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}
Edward Anthony Hernandez, Timothy David Highfield, T. Forbes, D. McLachlan
This paper will look at the technical, strategic and commercial benefits of Barge Liquified Natural Gas (BLNG) technology in Deepwater and Onshore gas developments. The majority of the Floating Liquified Natural Gas (FLNG) vessels currently operating are ship-shaped and destined for offshore, over-field locations. However, this approach does not necessarily offer the optimised solution for gas monetisation from Deepwater gas field. Equally where there is an abundant source of onshore gas, onshore LNG liquefaction plants have generally been selected, e.g. on the US Gulf Coast, this may also not be an optimised solution. An alternative solution in both these situations is BLNG, focused on nearshore positioning with LNG facilities mounted on a simple floating or grounded substructure with the balance of the systems (pre-processing, liquids handling, possibly storage etc.) decoupled from the liquefaction technology and in a separate location, such as a Central Processing Facility (CPF) FPSO in the deepwater or a gas processing facility near the development wells onshore. It is recognized that positioning the gas treatment facilities close to the wells normally enhances the overall recovery from the reservoirs as a lower back pressure can be achieved and gas compression added as required. An example of an overall field development scheme utilizing a nearshore BLNG plant with a deepwater FPSO CPF and a Liquified Natural Gas Carrier (LNGC) for storage is shown in BLNG Field Layout Solution for deepwater gas This paper addresses the following benefits of BLNG and why it's becoming increasingly viable as a gas monetization concept. Technical Potential risk reduction benefits in both the operating and construction phases. Offers a "design one, build many" philosophy enabling a more efficient production line or "factory" approach to fabrication. A multiple module LNG train configuration enables liquefaction to closely and efficiently match gas production rates. Smaller LNG trains have faster start-up/re-start times than world-scale LNG trains. Nearshore BLNG may be able to achieve a lower carbon footprint by utilising (a degree of) power from shore (e.g. from a hydroelectric system or other renewable source or a more efficient traditional solution), which ultimately increases safety, availability and enables more gas to be sold to the end user. Commercial With multiple small LNG trains the reduction in export capacity during planned or unplanned shutdowns is limited to only the capacity of a single train (i.e. gas turbine engine maintenance or exchange) and not the whole facility's output. A facility's capacity can easily be increased by additional barges and contractible in late field life, as the field moves off plateau. Strategic BLNG construction, fabrication and pre-commissioning can be performed in a dedicated yard rather than at a remote site. A controlled environment with an already skilled workforce in place, is advantageous versus
{"title":"BLNG: The Future of FLNG?","authors":"Edward Anthony Hernandez, Timothy David Highfield, T. Forbes, D. McLachlan","doi":"10.4043/29790-ms","DOIUrl":"https://doi.org/10.4043/29790-ms","url":null,"abstract":"\u0000 This paper will look at the technical, strategic and commercial benefits of Barge Liquified Natural Gas (BLNG) technology in Deepwater and Onshore gas developments.\u0000 The majority of the Floating Liquified Natural Gas (FLNG) vessels currently operating are ship-shaped and destined for offshore, over-field locations. However, this approach does not necessarily offer the optimised solution for gas monetisation from Deepwater gas field. Equally where there is an abundant source of onshore gas, onshore LNG liquefaction plants have generally been selected, e.g. on the US Gulf Coast, this may also not be an optimised solution.\u0000 An alternative solution in both these situations is BLNG, focused on nearshore positioning with LNG facilities mounted on a simple floating or grounded substructure with the balance of the systems (pre-processing, liquids handling, possibly storage etc.) decoupled from the liquefaction technology and in a separate location, such as a Central Processing Facility (CPF) FPSO in the deepwater or a gas processing facility near the development wells onshore. It is recognized that positioning the gas treatment facilities close to the wells normally enhances the overall recovery from the reservoirs as a lower back pressure can be achieved and gas compression added as required.\u0000 An example of an overall field development scheme utilizing a nearshore BLNG plant with a deepwater FPSO CPF and a Liquified Natural Gas Carrier (LNGC) for storage is shown in\u0000 BLNG Field Layout Solution for deepwater gas\u0000 This paper addresses the following benefits of BLNG and why it's becoming increasingly viable as a gas monetization concept.\u0000 Technical\u0000 Potential risk reduction benefits in both the operating and construction phases.\u0000 Offers a \"design one, build many\" philosophy enabling a more efficient production line or \"factory\" approach to fabrication.\u0000 A multiple module LNG train configuration enables liquefaction to closely and efficiently match gas production rates. Smaller LNG trains have faster start-up/re-start times than world-scale LNG trains.\u0000 Nearshore BLNG may be able to achieve a lower carbon footprint by utilising (a degree of) power from shore (e.g. from a hydroelectric system or other renewable source or a more efficient traditional solution), which ultimately increases safety, availability and enables more gas to be sold to the end user.\u0000 Commercial\u0000 With multiple small LNG trains the reduction in export capacity during planned or unplanned shutdowns is limited to only the capacity of a single train (i.e. gas turbine engine maintenance or exchange) and not the whole facility's output.\u0000 A facility's capacity can easily be increased by additional barges and contractible in late field life, as the field moves off plateau.\u0000 Strategic\u0000 BLNG construction, fabrication and pre-commissioning can be performed in a dedicated yard rather than at a remote site. A controlled environment with an already skilled workforce in place, is advantageous versus","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124496788","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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