Pub Date : 2020-01-13DOI: 10.2523/iptc-19995-abstract
Carlos Mendez Morales
Loss of circulation while drilling can create a multitude of problems during the well construction stage ranging from costly loss of drilling fluid and dry drilling up to well control issues leading to underground and surface blowout. Careful selection of casing depths to effectively isolate formations with varying pressure gradients from each other is essential for the integrity of the well and in consequence the safety and environment. Despite every care being taken in selecting casing points and drilling fluids that should keep the well in balance while avoiding overburden of the formation fracture pressure, losses can still occur suddenly and aggressively. In depleted carbonate reservoirs in the Middle East losses are a common occurrence which the majority of times are grueling to control through conventional methods. This paper discusses the ingenious application of an all-natural polymer based cement spacer including lost circulation material that was successfully applied in a hostile gas field in the Middle East. These wells can recurrently present abnormal pressure, which often leads to a formation breakdown while trying to provide well control due to the heavy mud weights utilized. By maintaining full circulation it was possible to ensure the well remained static, thus achieving zonal isolation and completing the well.
{"title":"Application of a Cement Spacer as a LCM Pill During Drilling Operations to Overcome Lost Circulation and Regain Well Control: A Case History in a Hostile Environment in the Middle East","authors":"Carlos Mendez Morales","doi":"10.2523/iptc-19995-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19995-abstract","url":null,"abstract":"\u0000 Loss of circulation while drilling can create a multitude of problems during the well construction stage ranging from costly loss of drilling fluid and dry drilling up to well control issues leading to underground and surface blowout. Careful selection of casing depths to effectively isolate formations with varying pressure gradients from each other is essential for the integrity of the well and in consequence the safety and environment. Despite every care being taken in selecting casing points and drilling fluids that should keep the well in balance while avoiding overburden of the formation fracture pressure, losses can still occur suddenly and aggressively. In depleted carbonate reservoirs in the Middle East losses are a common occurrence which the majority of times are grueling to control through conventional methods.\u0000 This paper discusses the ingenious application of an all-natural polymer based cement spacer including lost circulation material that was successfully applied in a hostile gas field in the Middle East. These wells can recurrently present abnormal pressure, which often leads to a formation breakdown while trying to provide well control due to the heavy mud weights utilized. By maintaining full circulation it was possible to ensure the well remained static, thus achieving zonal isolation and completing the well.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89431207","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}
Omran Al Zankawi, Aisha Yousef Al Ghareeb, Hemant Singh, S. Imtiaz, A. Khaksar, S. Perumalla
The mature Greater Burgan field has the largest clastic oil reservoir in the world producing from multiple units for more than 70 years. Wara and Burgan are the two main sandstone reservoirs in the field with several sub-units of varying mineralogical and mechanical properties. Continuous oil production from some low strength reservoir units has resulted in pressure depletion and the associated water encroachment has led to the initiation of sand production in few wells. This paper presents an approach to analyze rock mechanics, reservoir and production data to predict the sanding tendency in a heterogeneous rock of the world's largest clastic oil reservoir. Analytical poro-elastic geomechanical sanding evaluation approach was used to study rock failure and sand production. A number of wells (both with sand production and without sand production) were selected for geomechanical analysis based on the data availability and their respective location across the field. Various types of rock mechanical tests were performed with stringent quality control criteria to determine the mechanical characteristics of the rocks. Field calibrated geomechanical model along with reservoir and production data were used to build a calibrated sanding model for the Wara reservoir. The sanding model was then utilized to create sanding evaluation logs; perforation optimization and safe operating envelop plots for existing and future wells. As per the calibrated geomechanical model, the reservoir units comprise intervals of variable rock strengths. The sanding model calibrated from offset wells suggested that drawdown and rock strength are the most sensitive parameters in failing the rock and sand production. The wells with and without sanding had mixed response to water breakthrough and there does not seem to be any obvious pattern of sanding observed with respect to the onset of water production in the wells. It was also noticed that few offset wells did not exhibit sand production despite strength and stress conditions in these wells were favorable for early sand production. Potential explanation was found for those cases. These models helped to identify selective intervals to optimize sand-free production with limited drawdowns. However, for wells with very high drawdowns (installed with artificial lift pumps and 1000 psi drawdown pressure), none of the prolific sand interval could be stable and downhole sand control measures may be required. The combination of measured and modelled parameters have helped to understand the sanding tendency and behaviors of a highly heterogeneous reservoir. This analysis has produced guidelines on the best and worst well trajectories and optimum perforation orientations to mitigate well-life sanding risks with a rock strength sensitivity. Furthermore, data priorities have been identified in order to come up with holistic sand management strategy.
{"title":"Sand Production Tendency in the World's Largest Clastic Oil Reservoir - An Evolving Experience","authors":"Omran Al Zankawi, Aisha Yousef Al Ghareeb, Hemant Singh, S. Imtiaz, A. Khaksar, S. Perumalla","doi":"10.2523/iptc-20067-ms","DOIUrl":"https://doi.org/10.2523/iptc-20067-ms","url":null,"abstract":"\u0000 The mature Greater Burgan field has the largest clastic oil reservoir in the world producing from multiple units for more than 70 years. Wara and Burgan are the two main sandstone reservoirs in the field with several sub-units of varying mineralogical and mechanical properties. Continuous oil production from some low strength reservoir units has resulted in pressure depletion and the associated water encroachment has led to the initiation of sand production in few wells. This paper presents an approach to analyze rock mechanics, reservoir and production data to predict the sanding tendency in a heterogeneous rock of the world's largest clastic oil reservoir.\u0000 Analytical poro-elastic geomechanical sanding evaluation approach was used to study rock failure and sand production. A number of wells (both with sand production and without sand production) were selected for geomechanical analysis based on the data availability and their respective location across the field. Various types of rock mechanical tests were performed with stringent quality control criteria to determine the mechanical characteristics of the rocks. Field calibrated geomechanical model along with reservoir and production data were used to build a calibrated sanding model for the Wara reservoir. The sanding model was then utilized to create sanding evaluation logs; perforation optimization and safe operating envelop plots for existing and future wells.\u0000 As per the calibrated geomechanical model, the reservoir units comprise intervals of variable rock strengths. The sanding model calibrated from offset wells suggested that drawdown and rock strength are the most sensitive parameters in failing the rock and sand production. The wells with and without sanding had mixed response to water breakthrough and there does not seem to be any obvious pattern of sanding observed with respect to the onset of water production in the wells. It was also noticed that few offset wells did not exhibit sand production despite strength and stress conditions in these wells were favorable for early sand production. Potential explanation was found for those cases. These models helped to identify selective intervals to optimize sand-free production with limited drawdowns. However, for wells with very high drawdowns (installed with artificial lift pumps and 1000 psi drawdown pressure), none of the prolific sand interval could be stable and downhole sand control measures may be required.\u0000 The combination of measured and modelled parameters have helped to understand the sanding tendency and behaviors of a highly heterogeneous reservoir. This analysis has produced guidelines on the best and worst well trajectories and optimum perforation orientations to mitigate well-life sanding risks with a rock strength sensitivity. Furthermore, data priorities have been identified in order to come up with holistic sand management strategy.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81278285","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-20049-abstract
Mohamed Mohamed Elkordy, Bader Taqi Akbar, M. Patra, AbdulSamad Ahmad, Abdullah Abu Eida, Nasser Al Azmi, Abdulaziz Dashti, A. Stephens, H. Ayyad, Khaled Abdulrahim, A. Busaidy, G. Hernandez, Wahiba Grabssi
To reactivate wells that are not flowing, a common solution is to perforate any bypassed zone to bring the wells back to operation. If the completion does not allow for optimal interventions, i.e. running the perforating gun sized for the target interval, the consequences of a thru-tubing intervention must be evaluated based on cost, probability of success, risk and whether the potential results and the time savings of a rig are justifiable. In a well in Minagish Field of Kuwait, a combination of thru-tubing technologies was deployed for perforating a bypassed zone, reducing the cost of a rig workover, and maximizing the potential results. The conveyance method was selected in consideration of well access, cost, provision of positive depth correlation, and the capability to deploy the perforating guns thru tubing. Second, the perforating system was modeled with the reservoir parameters for its impact on well productivity. After the perforation parameters were obtained, the application of post-perforating dynamic underbalance was proposed to clean the perforations and reduce skin. Downhole measurements while perforating was combined with all the runs, including gamma ray, collar locator, pressure, temperature. A fast gauge was run in memory mode with the post perforating underbalance guns. The perforating operation was performed with a suite of measurements conveyed with digital slickline, enabling a cost-effective, informed intervention that reduced the operator's cost by USD 288,000 over a conventional rig-based operation. The combination of extra-deep penetrating shaped charges loaded a 2-1/8-in phased exposed carrier perforating guns system and the post-perforating cleanup system, restoring the well to a production of 1,500bbl/d. The application of digital slickline that provided downhole measurement while perforating was deployed for the first time in Kuwait. The use of productivity modeling for perforating proved to be a successful metric for decision making when selecting this intervention methodology. This approach saved the operator time and cost while cutting risks and maximizing the potential production restoration.
{"title":"Perforations Redefined: Measurements while Perforating using Digital Slickline","authors":"Mohamed Mohamed Elkordy, Bader Taqi Akbar, M. Patra, AbdulSamad Ahmad, Abdullah Abu Eida, Nasser Al Azmi, Abdulaziz Dashti, A. Stephens, H. Ayyad, Khaled Abdulrahim, A. Busaidy, G. Hernandez, Wahiba Grabssi","doi":"10.2523/iptc-20049-abstract","DOIUrl":"https://doi.org/10.2523/iptc-20049-abstract","url":null,"abstract":"\u0000 To reactivate wells that are not flowing, a common solution is to perforate any bypassed zone to bring the wells back to operation. If the completion does not allow for optimal interventions, i.e. running the perforating gun sized for the target interval, the consequences of a thru-tubing intervention must be evaluated based on cost, probability of success, risk and whether the potential results and the time savings of a rig are justifiable.\u0000 In a well in Minagish Field of Kuwait, a combination of thru-tubing technologies was deployed for perforating a bypassed zone, reducing the cost of a rig workover, and maximizing the potential results. The conveyance method was selected in consideration of well access, cost, provision of positive depth correlation, and the capability to deploy the perforating guns thru tubing. Second, the perforating system was modeled with the reservoir parameters for its impact on well productivity. After the perforation parameters were obtained, the application of post-perforating dynamic underbalance was proposed to clean the perforations and reduce skin. Downhole measurements while perforating was combined with all the runs, including gamma ray, collar locator, pressure, temperature. A fast gauge was run in memory mode with the post perforating underbalance guns.\u0000 The perforating operation was performed with a suite of measurements conveyed with digital slickline, enabling a cost-effective, informed intervention that reduced the operator's cost by USD 288,000 over a conventional rig-based operation. The combination of extra-deep penetrating shaped charges loaded a 2-1/8-in phased exposed carrier perforating guns system and the post-perforating cleanup system, restoring the well to a production of 1,500bbl/d.\u0000 The application of digital slickline that provided downhole measurement while perforating was deployed for the first time in Kuwait. The use of productivity modeling for perforating proved to be a successful metric for decision making when selecting this intervention methodology. This approach saved the operator time and cost while cutting risks and maximizing the potential production restoration.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80811266","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}
Hsu-hsiang Wu, A. Walmsley, Pan Li, D. Weixin, M. Bittar, S. Gear
Understanding reservoir fluid and facies distribution is crucial for optimal reservoir development. Ultra-deep, logging-while-drilling (LWD) resistivity measurements with a deep detection range into the formation have started a new chapter of formation evaluation. A hybrid inversion of statistical and deterministic approaches based on ultra-deep measurements has successfully determined formation resistivity profiles more than 100 ft away from drilled wellbores, providing proactive geosteering information for real-time well-placement decisions. However, the inversion sometimes produces artificial geological features because of so-called solution ambiguities attributable to lower measurement sensitivity in certain formation resistivity contrasts and reservoir geometries. Previously, geosteering geologists were trained to recognize such unrealistic geological structures based on multiple sources of information, rather than just the ultra-deep resistivity inversion results. This paper introduces machine-learning (ML) algorithms to evaluate the sensitivity of individual measurements, as well as to cluster the inverted models to acquire more geologically reasonable models of the surrounding formations. A case study shows significant improvement as a result of the ML algorithm in the structural consistency of the reservoirs. The boundaries were better determined with fine details using the ML algorithm, as compared to results from existing algorithms. The enhanced answer product enabled a better understanding of the formation properties surrounding the wellbore and retrieved several fine features that were not observed previously.
{"title":"Case Study: Using Machine Learning and Ultra-Deep-Reading Resistivity for Better Reservoir Delineation","authors":"Hsu-hsiang Wu, A. Walmsley, Pan Li, D. Weixin, M. Bittar, S. Gear","doi":"10.2523/iptc-20152-ms","DOIUrl":"https://doi.org/10.2523/iptc-20152-ms","url":null,"abstract":"\u0000 Understanding reservoir fluid and facies distribution is crucial for optimal reservoir development. Ultra-deep, logging-while-drilling (LWD) resistivity measurements with a deep detection range into the formation have started a new chapter of formation evaluation. A hybrid inversion of statistical and deterministic approaches based on ultra-deep measurements has successfully determined formation resistivity profiles more than 100 ft away from drilled wellbores, providing proactive geosteering information for real-time well-placement decisions. However, the inversion sometimes produces artificial geological features because of so-called solution ambiguities attributable to lower measurement sensitivity in certain formation resistivity contrasts and reservoir geometries. Previously, geosteering geologists were trained to recognize such unrealistic geological structures based on multiple sources of information, rather than just the ultra-deep resistivity inversion results.\u0000 This paper introduces machine-learning (ML) algorithms to evaluate the sensitivity of individual measurements, as well as to cluster the inverted models to acquire more geologically reasonable models of the surrounding formations. A case study shows significant improvement as a result of the ML algorithm in the structural consistency of the reservoirs. The boundaries were better determined with fine details using the ML algorithm, as compared to results from existing algorithms. The enhanced answer product enabled a better understanding of the formation properties surrounding the wellbore and retrieved several fine features that were not observed previously.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84362965","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}
Drilling offshore gas wells is a very challenging operation since it involves a high number of offshore rigs, mud losses into formation, well control and adverse weather conditions. All of which minimize the drilling efficiency on those wells with huge attendant cost, if no proper arrangement is put in place to mitigate these challenges. In the current setting where we can sometimes see rapid increase in offshore drilling operation challenges such as coping with severe drilling fluid losses into formations, the main challenge is to support offshore rigs with drilling fluid in a timely and seamless manner. As on-shore mud plant keeps up with a very high operational demand, launched and successfully implemented a new floating mud facility ("HUB") to improve supply and deliver mud materials and fluids to offshore drilling rigs. This floating mud and chemicals storage plant (HUB) spot successfully reduced transit times, minimized delays and nonproductive time previously experienced by the drilling rigs operating in offshore gas fields. These delays were due to late drilling fluid deliveries from the onshore mud plant and extended times to mix high-density fluids on the rigs. This innovative model guarantees significant savings in terms of saving mixing times, providing chemical storage capacity, consequently minimizing unnecessary rig site operations. There is also a significant reduction in environmental, health, safety, and risk exposure resulting in optimized shipping, distribution, back loading of drilling fluids, reduction in the utilization of supply vessels and rig resources, to support severe lost circulation or well control events. The HUB floating plant provides a full array of scalable fluids, mixing equipment and facilities to meet offshore operational requirements while eliminating the cost, extended lead-time, and specialized shipping. This plant encompasses a floating installation to mix and store drilling and completion fluids and chemicals. The HUB floating plant is equipped with twin mixing systems with the ability to mix and safely store more than 20,000 bbl of different fluid sets. It was recently utilized to mix high-density MICROMAX (manganese tetroxide) based completion fluid with excellent performance, despite the complexity of mixing over 2,500 metric tons (super-sacks), and still was able to handle different fluids seamlessly. This HUB is anchored within equal distance to the three largest gas fields. The reduction in delivery time is estimated to be 90% in both normal and emergency operations. Weighting materials and mud chemical storage capacity provides an additional platform to minimize rig deck utilization and drilling mud mixing construction capabilities, minimizing the huge coping pressure on the alternative onshore mud plant operations. Over the last 3 years of being in operation, the HUB floating plant has mixed more than 916,000 bbl of heavy mud and completion fluid, received over 19,000 bbl for storage, and
{"title":"Floating Mud Plant HUB: A Game-Changer in Offshore Drilling Logistics","authors":"Ernesto S. Gomez, H. Osorio, I. Obi, Ismaeel Musa","doi":"10.2523/iptc-20041-ms","DOIUrl":"https://doi.org/10.2523/iptc-20041-ms","url":null,"abstract":"\u0000 Drilling offshore gas wells is a very challenging operation since it involves a high number of offshore rigs, mud losses into formation, well control and adverse weather conditions. All of which minimize the drilling efficiency on those wells with huge attendant cost, if no proper arrangement is put in place to mitigate these challenges.\u0000 In the current setting where we can sometimes see rapid increase in offshore drilling operation challenges such as coping with severe drilling fluid losses into formations, the main challenge is to support offshore rigs with drilling fluid in a timely and seamless manner. As on-shore mud plant keeps up with a very high operational demand, launched and successfully implemented a new floating mud facility (\"HUB\") to improve supply and deliver mud materials and fluids to offshore drilling rigs.\u0000 This floating mud and chemicals storage plant (HUB) spot successfully reduced transit times, minimized delays and nonproductive time previously experienced by the drilling rigs operating in offshore gas fields. These delays were due to late drilling fluid deliveries from the onshore mud plant and extended times to mix high-density fluids on the rigs. This innovative model guarantees significant savings in terms of saving mixing times, providing chemical storage capacity, consequently minimizing unnecessary rig site operations. There is also a significant reduction in environmental, health, safety, and risk exposure resulting in optimized shipping, distribution, back loading of drilling fluids, reduction in the utilization of supply vessels and rig resources, to support severe lost circulation or well control events.\u0000 The HUB floating plant provides a full array of scalable fluids, mixing equipment and facilities to meet offshore operational requirements while eliminating the cost, extended lead-time, and specialized shipping. This plant encompasses a floating installation to mix and store drilling and completion fluids and chemicals. The HUB floating plant is equipped with twin mixing systems with the ability to mix and safely store more than 20,000 bbl of different fluid sets. It was recently utilized to mix high-density MICROMAX (manganese tetroxide) based completion fluid with excellent performance, despite the complexity of mixing over 2,500 metric tons (super-sacks), and still was able to handle different fluids seamlessly. This HUB is anchored within equal distance to the three largest gas fields. The reduction in delivery time is estimated to be 90% in both normal and emergency operations. Weighting materials and mud chemical storage capacity provides an additional platform to minimize rig deck utilization and drilling mud mixing construction capabilities, minimizing the huge coping pressure on the alternative onshore mud plant operations.\u0000 Over the last 3 years of being in operation, the HUB floating plant has mixed more than 916,000 bbl of heavy mud and completion fluid, received over 19,000 bbl for storage, and ","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86893001","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}
Soumi Chaki, Yevgeniy Zagayevskiy, Xuebei Shi, Wong Terry, Zainub Noor
A methodology to construct deep neural network- (DNN) and recurrent neural network- (RNN) based proxy flow models is presented; these can reduce computational time of the flow simulation runs in the routine reservoir engineering workflows, such as history matching or optimization. A comparison of these two techniques shows that the DNN model generates predictions more quickly, but the RNN model provides better quality. In addition, RNN-based proxy flow models can make predictions for times after those included in the training data set. Both approaches can reduce computational time by a factor of up to 100 in comparison to the full-physics flow simulator. An example of the proxy flow model application is successfully demonstrated in an exhaustive search history matching exercise. All developments are shown on a synthesized Brugge petroleum reservoir.
{"title":"Machine Learning for Proxy Modeling of Dynamic Reservoir Systems: Deep Neural Network DNN and Recurrent Neural Network RNN Applications","authors":"Soumi Chaki, Yevgeniy Zagayevskiy, Xuebei Shi, Wong Terry, Zainub Noor","doi":"10.2523/iptc-20118-ms","DOIUrl":"https://doi.org/10.2523/iptc-20118-ms","url":null,"abstract":"\u0000 A methodology to construct deep neural network- (DNN) and recurrent neural network- (RNN) based proxy flow models is presented; these can reduce computational time of the flow simulation runs in the routine reservoir engineering workflows, such as history matching or optimization. A comparison of these two techniques shows that the DNN model generates predictions more quickly, but the RNN model provides better quality. In addition, RNN-based proxy flow models can make predictions for times after those included in the training data set. Both approaches can reduce computational time by a factor of up to 100 in comparison to the full-physics flow simulator. An example of the proxy flow model application is successfully demonstrated in an exhaustive search history matching exercise. All developments are shown on a synthesized Brugge petroleum reservoir.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73386107","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 gas-lift well sometimes suffers from slugging. As slugs reduce production volumes and cause other issues on the surface, we would like to mitigate or avoid them. The production choke and gas injection choke are two points at which the operator may influence the slug. For this to work, the operator must know that a slug is going to occur in advance so that avoidance actions can be implemented. The operator also needs to know by how much to change each choke. We find that a slug can be forecast successfully five hours in advance given typical field instrumentation of the well. This is based on an LSTM machine learning approach given historical data only.
{"title":"Preventing Slugging by Tuning Choke through Machine Learning","authors":"P. Bangert","doi":"10.2523/19931-abstract","DOIUrl":"https://doi.org/10.2523/19931-abstract","url":null,"abstract":"\u0000 A gas-lift well sometimes suffers from slugging. As slugs reduce production volumes and cause other issues on the surface, we would like to mitigate or avoid them. The production choke and gas injection choke are two points at which the operator may influence the slug. For this to work, the operator must know that a slug is going to occur in advance so that avoidance actions can be implemented. The operator also needs to know by how much to change each choke. We find that a slug can be forecast successfully five hours in advance given typical field instrumentation of the well. This is based on an LSTM machine learning approach given historical data only.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80236843","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 explores the fluid displacement of extended-reach drilled (ERD) wells in relation to density hierarchy. Historically, less emphasis has been placed on the proper density hierarchy for the fluid train in ERD wells because the wells are horizontal. Through sensitivity analysis, the significance of fluid density differences is demonstrated. Fluid displacement in ERD wells is different from conventional wells. Various factors influence fluid displacement in primary cementing, including rheology and density differences between fluids. Rheological differences affect fluid displacement by changing the fluid velocity profile in the mixed zone, whereas density differences affect fluid displacement through additional gravitational force on the fluids. Gravity does not affect the way rheological differences impact the fluid profiles. Unlike rheological differences, the direction of gravitational forces with reference to the flow direction is perpendicular for an ERD well compared to a conventional well (vertical or deviated); thus, the resulting flow pattern exclusively resulting from density differences is not similar between the two well configurations. A new finite-volume-based three-dimensional (3D) displacement model was used to understand the effect of the key characteristic (density) of fluid displacement in ERD wells. The model is capable of accurately capturing the rheological behavior of the fluids using a best-fit rheological model and features time-dependent fluid evolution in both the pipe and annulus under the influence of pipe rotation and reciprocation. This work presents a comprehensive sensitivity analysis for the effects of density differences between successive fluids in ERD well configurations and their interaction with other parameters, such as rheology differences, fluid velocities, and pipe movement. This paper augments the current industry understanding of density hierarchy in ERD well scenarios and also includes case studies comparing predicted cement placement to that of cement bond logs (CBLs) in ERD wells.
{"title":"Understanding Fluid Displacement in Extended-Reach Drilled Wells","authors":"K. Yerubandi, K. Hennessy, Anoop Jogdand","doi":"10.2523/iptc-20330-ms","DOIUrl":"https://doi.org/10.2523/iptc-20330-ms","url":null,"abstract":"\u0000 This paper explores the fluid displacement of extended-reach drilled (ERD) wells in relation to density hierarchy. Historically, less emphasis has been placed on the proper density hierarchy for the fluid train in ERD wells because the wells are horizontal. Through sensitivity analysis, the significance of fluid density differences is demonstrated.\u0000 Fluid displacement in ERD wells is different from conventional wells. Various factors influence fluid displacement in primary cementing, including rheology and density differences between fluids. Rheological differences affect fluid displacement by changing the fluid velocity profile in the mixed zone, whereas density differences affect fluid displacement through additional gravitational force on the fluids. Gravity does not affect the way rheological differences impact the fluid profiles. Unlike rheological differences, the direction of gravitational forces with reference to the flow direction is perpendicular for an ERD well compared to a conventional well (vertical or deviated); thus, the resulting flow pattern exclusively resulting from density differences is not similar between the two well configurations.\u0000 A new finite-volume-based three-dimensional (3D) displacement model was used to understand the effect of the key characteristic (density) of fluid displacement in ERD wells. The model is capable of accurately capturing the rheological behavior of the fluids using a best-fit rheological model and features time-dependent fluid evolution in both the pipe and annulus under the influence of pipe rotation and reciprocation. This work presents a comprehensive sensitivity analysis for the effects of density differences between successive fluids in ERD well configurations and their interaction with other parameters, such as rheology differences, fluid velocities, and pipe movement.\u0000 This paper augments the current industry understanding of density hierarchy in ERD well scenarios and also includes case studies comparing predicted cement placement to that of cement bond logs (CBLs) in ERD wells.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89325106","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19769-abstract
Yilin Fan, E. Al-Safran, E. Pereyra, C. Sarica
Pseudo-slug flow is a sub-regime of intermittent flow that is characterized by short, undeveloped, frothy chaotic slugs, with translational velocity less than the mixture velocity of the fluids. Pseudo-slug flow does not comply with the basic characteristics of conventional unit-cell slug flow where liquid blocks the entire pipe cross-sectional area, and liquid is scooped at slug front, transferred to slug body, and shed back to liquid film. The liquid in pseudo-slug body is insufficient to reach the upper part of the pipe wall, resulting in only large wave with entrained gas bubbles at the bottom part of the pseudo slug body. Consequently, a significant reduction in the gas phase flowing area above the wave is formed, which increases the local gas velocity, entraining large volume of liquid droplets in the upper part of the slug body. Therefore, the pseudo-slug body can be divided into two regions, liquid film (wave) with entrained gas bubbles at the bottom, and gas core with entrained liquid droplets. The objective of this study is to develop a plausible physical model of the experimentally observed pseudo-slug liquid holdup phenomenon and model the physical and hydrodynamic behavior using a dimensional regression modeling approach. This paper discusses liquid and gas entrainment mechanisms within pseudo-slug body based on experimental observation. Previous experimental results show that the proposed dimensionless groups; namely, Stokes, Slippage, and Poiseuille are strongly correlated to pseudo-slug body liquid holdup experimental data and are capable of describing the experimentally observed physical behavior. A linearized regression model is developed to combine the liquid holdup proportionally in both regions of the pseudo-slug body (mentioned above) and correlate them to the experimentally measured total pseudo-slug liquid holdup using wire mesh sensor. A validation study of the proposed model with Fan (2017) experimental data shows good agreement, outperforming all other existing slug liquid holdup correlations.
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Pub Date : 2020-01-13DOI: 10.2523/iptc-19635-abstract
M. Al-Masrahy
Petroleum is common and abundant in wind-laid rocks in many places in the world, and aeolian deposits typically form good reservoirs or pathways for hydrocarbon migration due to their high initial porosity and permeability, and the generally great lateral continuity of preserved elements. Subsequently, heterogeneity in such aeolian successions, e.g., arising due to the juxtaposition of dune and interdune elements, can be problematic; therefore, there is a need to develop quantitative models for predicting the arrangement of such elements in subsurface successions. The Artinskian-Kungurian Upper Unayzah Formation displays widespread evidence of deposition in a continental setting under the influence of an arid to semi-arid climatic regime, commonly in a wind dominated, aeolian setting. In the study areas, a number of distinctive aeolian depositional facies are recognized from subsurface cores and image logs, including: aeolian sand dune, interdune/damp sandflat, sand sheets/dry sandflat and ephemeral playa lake palaeo-environments. The facies occur with a high degree of vertical and areal repeatability throughout the studied successions. The study further investigated distribution of azimuthal variability of the cross-bedded sandstone's aeolian sand dune facies in the Lower Permian, utilizing microresistivity borehole image logs. A palaeo-wind data study involved the analysis of image log data from several wells. To investigate the palaeo-wind directions from the measured subsurface azimuthal data, a hierarchical approach was employed as follows: (i) azimuth data recorded for each identifiable bed, (ii) averaged over each bedset within each well, (iii) averaged over each well, (iv) averaged over each area, and (v) averaged over the four studied areas. This rigorous approach resulted in the identification of a resultant drift direction toward east-northeast (relative to the present day), with a range that varied between 40° and 100° with a mean direction of 72 azimuth degrees. The final stage of this study was to analyze wind data obtained from modern analogues to further understand and evaluate the sand drift directions and potentials. Identification of the dominant palaeo-wind direction served as the basis for developing a model for palaeo-environmental spatial and temporal variations in dune distribution and planform morphological type throughout the studied areas. This model then formed a principal tool used for field development plans by enabling prediction and mapping of porosity and permeability distributions.
{"title":"Significance of Aeolian Deposits Resultant Drift Direction, Implications for Reservoir Prediction, Utilizing Subsurface and Analogue Data","authors":"M. Al-Masrahy","doi":"10.2523/iptc-19635-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19635-abstract","url":null,"abstract":"\u0000 Petroleum is common and abundant in wind-laid rocks in many places in the world, and aeolian deposits typically form good reservoirs or pathways for hydrocarbon migration due to their high initial porosity and permeability, and the generally great lateral continuity of preserved elements. Subsequently, heterogeneity in such aeolian successions, e.g., arising due to the juxtaposition of dune and interdune elements, can be problematic; therefore, there is a need to develop quantitative models for predicting the arrangement of such elements in subsurface successions.\u0000 The Artinskian-Kungurian Upper Unayzah Formation displays widespread evidence of deposition in a continental setting under the influence of an arid to semi-arid climatic regime, commonly in a wind dominated, aeolian setting. In the study areas, a number of distinctive aeolian depositional facies are recognized from subsurface cores and image logs, including: aeolian sand dune, interdune/damp sandflat, sand sheets/dry sandflat and ephemeral playa lake palaeo-environments. The facies occur with a high degree of vertical and areal repeatability throughout the studied successions. The study further investigated distribution of azimuthal variability of the cross-bedded sandstone's aeolian sand dune facies in the Lower Permian, utilizing microresistivity borehole image logs. A palaeo-wind data study involved the analysis of image log data from several wells. To investigate the palaeo-wind directions from the measured subsurface azimuthal data, a hierarchical approach was employed as follows: (i) azimuth data recorded for each identifiable bed, (ii) averaged over each bedset within each well, (iii) averaged over each well, (iv) averaged over each area, and (v) averaged over the four studied areas.\u0000 This rigorous approach resulted in the identification of a resultant drift direction toward east-northeast (relative to the present day), with a range that varied between 40° and 100° with a mean direction of 72 azimuth degrees. The final stage of this study was to analyze wind data obtained from modern analogues to further understand and evaluate the sand drift directions and potentials. Identification of the dominant palaeo-wind direction served as the basis for developing a model for palaeo-environmental spatial and temporal variations in dune distribution and planform morphological type throughout the studied areas. This model then formed a principal tool used for field development plans by enabling prediction and mapping of porosity and permeability distributions.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89616219","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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