This paper presents a comprehensive laboratory protocol to evaluate and characterize the in-situ rock and fluid samples from the Viking Formation in the Western Canadian Sedimentary Basin (WCSB). The experiments are performed in four stages. In stage 1, we conduct Scanning Electron Microscopy (SEM), Energy-dispersive X-ray Spectroscopy (EDS) and X-ray Diffraction (XRD) techniques on the dry end-pieces of the plugs for pore-scale visualization and compositional analysis. In stage 2, we measure the contact angle (CA) of the equilibrated oil and brine droplets on the surface of the rock samples in the presence of air, and that of the equilibrated oil droplets on oil-saturated rock samples immersed in brine and DIW (deionized water). In stage 3, we perform co-current spontaneous imbibition experiments on a set of twin plugs to compare the rate of brine and oil uptake by capillary suction. In stage 4, we conduct counter-current imbibition experiments on oil-saturated plugs to evaluate oil recovery by DIW and brine. Co-current spontaneous imbibition results show excess brine uptake compared with oil during the early times (first 120 hours). The XRD results show the presence of 11.66 wt. % pore-filling clay minerals (10 wt.% kaolinite and 1.66 wt. % illite) in the selected rock samples. These clay minerals are dispersed in the pore structure of the selected rock samples, as observed in the SEM images taken from these samples. Therefore, it can be concluded that water adsorption by pore-filling clay minerals is the main reason for the excess brine uptake compared with oil at the early times. Although brine imbibes faster and more than oil at the early times, the final imbibed volume of oil is higher than brine, which indicates the presence of small hydrophobic pores with more affinity towards oil than brine. The CA of the equilibrated oil droplet on the surface of the oil-saturated reservoir rock immersed in brine is 114.0°, while that in DIW is 70.43°, indicating that DIW enhances the water-wetness of the reservoir rock by 43.6°. The results of the counter-current imbibition experiments on the oil-saturated plugs show that oil recovery by DIW is 33% of the initial oil volume in the plug, which is 5% more oil than that by the reservoir brine, primarily due to more significant osmotic potential.
{"title":"Advances in Understanding the Wettability of the Viking Formation","authors":"Saman Mohammadi, Tianyi Lan, Hassan Dehghanpour","doi":"10.2118/218076-ms","DOIUrl":"https://doi.org/10.2118/218076-ms","url":null,"abstract":"\u0000 This paper presents a comprehensive laboratory protocol to evaluate and characterize the in-situ rock and fluid samples from the Viking Formation in the Western Canadian Sedimentary Basin (WCSB). The experiments are performed in four stages. In stage 1, we conduct Scanning Electron Microscopy (SEM), Energy-dispersive X-ray Spectroscopy (EDS) and X-ray Diffraction (XRD) techniques on the dry end-pieces of the plugs for pore-scale visualization and compositional analysis. In stage 2, we measure the contact angle (CA) of the equilibrated oil and brine droplets on the surface of the rock samples in the presence of air, and that of the equilibrated oil droplets on oil-saturated rock samples immersed in brine and DIW (deionized water). In stage 3, we perform co-current spontaneous imbibition experiments on a set of twin plugs to compare the rate of brine and oil uptake by capillary suction. In stage 4, we conduct counter-current imbibition experiments on oil-saturated plugs to evaluate oil recovery by DIW and brine.\u0000 Co-current spontaneous imbibition results show excess brine uptake compared with oil during the early times (first 120 hours). The XRD results show the presence of 11.66 wt. % pore-filling clay minerals (10 wt.% kaolinite and 1.66 wt. % illite) in the selected rock samples. These clay minerals are dispersed in the pore structure of the selected rock samples, as observed in the SEM images taken from these samples. Therefore, it can be concluded that water adsorption by pore-filling clay minerals is the main reason for the excess brine uptake compared with oil at the early times. Although brine imbibes faster and more than oil at the early times, the final imbibed volume of oil is higher than brine, which indicates the presence of small hydrophobic pores with more affinity towards oil than brine. The CA of the equilibrated oil droplet on the surface of the oil-saturated reservoir rock immersed in brine is 114.0°, while that in DIW is 70.43°, indicating that DIW enhances the water-wetness of the reservoir rock by 43.6°. The results of the counter-current imbibition experiments on the oil-saturated plugs show that oil recovery by DIW is 33% of the initial oil volume in the plug, which is 5% more oil than that by the reservoir brine, primarily due to more significant osmotic potential.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"26 S68","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394911","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}
Wajid Ali, A. A. Hashmi, Faisal Abdullah Al Turki, Mouloud Bouaraki, Moaathe A. Aljardan
A major challenge that is faced during the well construction phase is to cement the formations holding narrow pressure margins between the pore and fracture gradients without inducing losses that could compromise the integrity of the cement barrier. The paper will review two case studies for deploying an engineered loss circulation (LC) spacer system as an important solution for primary cementing operations in the case study wells with such narrow pressure margins. One of the case studies well is a land well where a high-pressure influx was encountered while drilling an 8-3/8-in hole across a water-bearing formation. A narrow pressure gradient persuaded to utilize a managed pressure drilling (MPD) system. The well was drilled to the target depth using 138 lbm/ft3 oil-based mud drilling fluid while maintaining the equivalent circulation density (ECD) from 146.5 to 149.5 lbm/ft3. A 150 lbm/ft3 slurry was designed to keep the ECD intact. Additionally, the spacer was loaded with optimum amounts of surfactant package to help remove the mud and to water-wet the formation and pipe to achieve better cement bonding. It was observed that the engineered LC spacer provided safe isolation of low fracture gradient zones cost-effectively, even in challenging narrow-pressure window scenarios. The LC Spacer was able to mitigate the loss circulation while cementing due to the utilization of ultra-low invasion technology, which created a barrier across loss circulation zones. It was also observed that the LC spacer formed a shield across formation walls and reduced the loss circulation, ranging from partial to total losses on permeable, fragile, weak formations, naturally fractured reservoirs, and depleted reservoirs. The LC spacer also improved wellbore stability and ECDs along the wellbore and expected loss zones. Ultimately, the paper concludes that LC Spacer can be designed to address the challenge of minimizing losses during the primary cement job by offering superior sealing capabilities. The case studies present an overview of the engineering process used to plan critical liner cement jobs using a specialized LC spacer system. This paper reviews the execution of two successful liner jobs and presents findings and lessons learned. After the successful results on these jobs and subsequent operations, this spacer system is now being adopted to optimize cementing, where losses during cementing operations in the past have forced the modification of well construction.
{"title":"Technology Advancements in Loss Circulation (LC) Spacer Deployment Across a Narrow Pressure Window for Critical Liner Cement Jobs: Case Studies from Saudi Arabia","authors":"Wajid Ali, A. A. Hashmi, Faisal Abdullah Al Turki, Mouloud Bouaraki, Moaathe A. Aljardan","doi":"10.2118/218086-ms","DOIUrl":"https://doi.org/10.2118/218086-ms","url":null,"abstract":"\u0000 A major challenge that is faced during the well construction phase is to cement the formations holding narrow pressure margins between the pore and fracture gradients without inducing losses that could compromise the integrity of the cement barrier. The paper will review two case studies for deploying an engineered loss circulation (LC) spacer system as an important solution for primary cementing operations in the case study wells with such narrow pressure margins.\u0000 One of the case studies well is a land well where a high-pressure influx was encountered while drilling an 8-3/8-in hole across a water-bearing formation. A narrow pressure gradient persuaded to utilize a managed pressure drilling (MPD) system. The well was drilled to the target depth using 138 lbm/ft3 oil-based mud drilling fluid while maintaining the equivalent circulation density (ECD) from 146.5 to 149.5 lbm/ft3. A 150 lbm/ft3 slurry was designed to keep the ECD intact. Additionally, the spacer was loaded with optimum amounts of surfactant package to help remove the mud and to water-wet the formation and pipe to achieve better cement bonding.\u0000 It was observed that the engineered LC spacer provided safe isolation of low fracture gradient zones cost-effectively, even in challenging narrow-pressure window scenarios. The LC Spacer was able to mitigate the loss circulation while cementing due to the utilization of ultra-low invasion technology, which created a barrier across loss circulation zones. It was also observed that the LC spacer formed a shield across formation walls and reduced the loss circulation, ranging from partial to total losses on permeable, fragile, weak formations, naturally fractured reservoirs, and depleted reservoirs. The LC spacer also improved wellbore stability and ECDs along the wellbore and expected loss zones. Ultimately, the paper concludes that LC Spacer can be designed to address the challenge of minimizing losses during the primary cement job by offering superior sealing capabilities.\u0000 The case studies present an overview of the engineering process used to plan critical liner cement jobs using a specialized LC spacer system. This paper reviews the execution of two successful liner jobs and presents findings and lessons learned. After the successful results on these jobs and subsequent operations, this spacer system is now being adopted to optimize cementing, where losses during cementing operations in the past have forced the modification of well construction.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"67 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284767","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 technical paper addresses the challenges faced by Montney producers in northwestern Alberta and northeastern British Columbia due to downhole calcite and barite deposition. These scales lead to various issues such as production declines, pressure increases, decreased pump efficiency, and equipment failures. Additionally, the presence of Naturally Occurring Radioactive Materials (NORMs) associated with barite poses health concerns and disposal expenses. Continuously applied scale inhibitors are unable to reach the pay zone in the horizontal section, which has multiple fractures in a low-porosity and low-permeability formation. In response to these challenges, a comprehensive database of water analyses for the Montney was used to understand the variability in scaling ions. Scale modeling under bottomhole and topside conditions was conducted to gain insights into scaling dynamics. Laboratory performance of a range of system-compatible scale inhibitors was evaluated using dynamic scale loop and particle size analysis through focused beam reflectance measurement (FBRM) tests. The study focused on candidate wells with pump lifespans of less than three months, and scale squeezes were performed on both beam pump and gas lift wells. Drawing upon best practices from scale squeezes in the Saskatchewan, Montana, and North Dakota Bakken Formation, a scale squeeze program was developed. Monitoring during the program involved comparative water analyses, scale inhibitor residuals, and NORM monitoring. Results showed that the scale squeezes led to increased pump lifespans for beam-pumped wells, elimination of NORM in surface equipment, reduced acid cleanouts, and minimized downtime. The success of the scale squeeze program proved the feasibility of applying this approach in the Montney and offered support for its extension to other shale plays across Western Canada and worldwide.
{"title":"Mitigating Downhole Calcite and Barite Deposition in the Montney: A Successful Scale Squeeze Program","authors":"J. Schmid, B. Aiken, F. El Yaakobi, L. Colmenares","doi":"10.2118/218056-ms","DOIUrl":"https://doi.org/10.2118/218056-ms","url":null,"abstract":"\u0000 This technical paper addresses the challenges faced by Montney producers in northwestern Alberta and northeastern British Columbia due to downhole calcite and barite deposition. These scales lead to various issues such as production declines, pressure increases, decreased pump efficiency, and equipment failures. Additionally, the presence of Naturally Occurring Radioactive Materials (NORMs) associated with barite poses health concerns and disposal expenses. Continuously applied scale inhibitors are unable to reach the pay zone in the horizontal section, which has multiple fractures in a low-porosity and low-permeability formation.\u0000 In response to these challenges, a comprehensive database of water analyses for the Montney was used to understand the variability in scaling ions. Scale modeling under bottomhole and topside conditions was conducted to gain insights into scaling dynamics. Laboratory performance of a range of system-compatible scale inhibitors was evaluated using dynamic scale loop and particle size analysis through focused beam reflectance measurement (FBRM) tests.\u0000 The study focused on candidate wells with pump lifespans of less than three months, and scale squeezes were performed on both beam pump and gas lift wells. Drawing upon best practices from scale squeezes in the Saskatchewan, Montana, and North Dakota Bakken Formation, a scale squeeze program was developed. Monitoring during the program involved comparative water analyses, scale inhibitor residuals, and NORM monitoring.\u0000 Results showed that the scale squeezes led to increased pump lifespans for beam-pumped wells, elimination of NORM in surface equipment, reduced acid cleanouts, and minimized downtime. The success of the scale squeeze program proved the feasibility of applying this approach in the Montney and offered support for its extension to other shale plays across Western Canada and worldwide.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"106 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395669","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}
K. Husby, M. Hjelstuen, T. J. Eriksen, A. Saasen, J. D. Ytrehus, A. Liberale, M. Koraei
In the enterprise of creating a geothermal loop deep in a formation it may be necessary to drill an intercept with another well. This intercept has some similarities with the well intercept needed when drilling a relief well in cases of blow out of gas or oil wells. At the same time, it is necessary to avoid colliding with the other well prior to reaching the intercept point. A constant distance may be required to the other well at some well depths. A prototype of a tool for Active Magnetic Ranging While Drilling (AMR) without the use of a wireline operation has been developed to navigate for distance control or intercept. The main scope of the current article is to present the results of a prototype test of this new tool in a test well suitable to simulate geothermal well. The ranging tool emits a low frequency alternating current into the formation to reach the target well. The current then run down the target well’s casing and back to the well being drilled. This electric current set up a variable magnetic field that is measured by the AMR tool determining the distance to and the direction towards the target well. Hence, the tool facilitates drilling radiator shape multi-lateral well paths. If drilling an intercept at the end of the radiator sections, 10 - 25 wireline runs are needed in each lateral to the target well is intercepted. The present AMR tool is fully integrated in the drill pipe and, thus, all the tripping operations are avoided. A prototype of an active magnetic ranging tool on the drill pipe has been developed. This tool design is outlined in the paper. The focus is given to performance tests conducted in research wells in Norway. A drill pipe is placed in a vertical well drilled in a gneiss formation. This well simulates a target well. The AMR tool was run in a parallel well and the direction and distance to the nearby target well was measured. The gneiss formation would be a tough formation to drill. However, this formation type is suitable for testing drilling in geothermal well formations. The set-up and the results of this logging operation conducted on a drill pipe is described in detail. It is shown how the direction and distance between the two wells are measured using the tool.
在地层深处创建地热环路的过程中，可能需要钻探另一口井的截距。这种拦截与天然气井或油井发生井喷时钻探溢流井所需的拦截井有一些相似之处。同时，有必要避免在到达截取点之前与另一口井发生碰撞。在某些井深，可能需要与另一口井保持一定的距离。目前已开发出一种不使用导线作业的钻井时主动磁力测距（AMR）工具原型，用于导航以控制距离或拦截。本文的主要内容是介绍这一新工具原型在一口适合模拟地热井的试验井中的测试结果。测距工具向地层发射低频交流电，以到达目标井。然后，电流沿着目标井的套管向下运行，并返回到正在钻探的井中。这种电流会产生一个可变磁场，由 AMR 工具测量，确定目标井的距离和方向。因此，该工具有助于钻探辐射状多侧井道。如果在辐射段末端钻井截获目标井，则每个侧向需要 10 - 25 次导线运行。目前的主动磁性测距仪完全集成在钻杆中，因此避免了所有的跳动操作。钻杆上的主动磁性测距工具原型已经开发出来。本文概述了该工具的设计。重点是在挪威的研究井中进行的性能测试。在片麻岩地层中钻的一口垂直井中放置了一根钻杆。这口井模拟一口目标井。AMR 工具在一口平行井中运行，并测量与附近目标井的方向和距离。片麻岩地层是一种难以钻探的地层。不过，这种地层类型适合在地热井地层中进行钻井测试。本文详细介绍了在钻杆上进行测井作业的设置和结果。图中显示了如何使用该工具测量两口井之间的方向和距离。
{"title":"Active Magnetic Ranging Solution While Drilling for Geothermal Loop: Test in Low-Conductive Formation","authors":"K. Husby, M. Hjelstuen, T. J. Eriksen, A. Saasen, J. D. Ytrehus, A. Liberale, M. Koraei","doi":"10.2118/218055-ms","DOIUrl":"https://doi.org/10.2118/218055-ms","url":null,"abstract":"\u0000 In the enterprise of creating a geothermal loop deep in a formation it may be necessary to drill an intercept with another well. This intercept has some similarities with the well intercept needed when drilling a relief well in cases of blow out of gas or oil wells. At the same time, it is necessary to avoid colliding with the other well prior to reaching the intercept point. A constant distance may be required to the other well at some well depths. A prototype of a tool for Active Magnetic Ranging While Drilling (AMR) without the use of a wireline operation has been developed to navigate for distance control or intercept. The main scope of the current article is to present the results of a prototype test of this new tool in a test well suitable to simulate geothermal well.\u0000 The ranging tool emits a low frequency alternating current into the formation to reach the target well. The current then run down the target well’s casing and back to the well being drilled. This electric current set up a variable magnetic field that is measured by the AMR tool determining the distance to and the direction towards the target well. Hence, the tool facilitates drilling radiator shape multi-lateral well paths. If drilling an intercept at the end of the radiator sections, 10 - 25 wireline runs are needed in each lateral to the target well is intercepted. The present AMR tool is fully integrated in the drill pipe and, thus, all the tripping operations are avoided.\u0000 A prototype of an active magnetic ranging tool on the drill pipe has been developed. This tool design is outlined in the paper. The focus is given to performance tests conducted in research wells in Norway. A drill pipe is placed in a vertical well drilled in a gneiss formation. This well simulates a target well. The AMR tool was run in a parallel well and the direction and distance to the nearby target well was measured. The gneiss formation would be a tough formation to drill. However, this formation type is suitable for testing drilling in geothermal well formations. The set-up and the results of this logging operation conducted on a drill pipe is described in detail. It is shown how the direction and distance between the two wells are measured using the tool.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"78 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395767","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}
Mohammed El sgher, K. Aminian, Vida Matey-Korley, S. Ameri
This study investigates the effect of fluid type and stress shadow on proppant transport and the productivity of a multi-stage fractured Marcellus Shale horizontal well. Additionally, the relation between stress shadow and effective stress is studies to optimize fracture effectiveness. This study’s findings can be compared with similar study performed on a different Marcellus shale well. Furthermore, the extent to which various fracture properties contribute to production is evaluated. The available core plugs measurements, well logs, and the image logs were analyzed to determine the shale petrophysical and geomechanical properties including natural fracture (fissure) distribution to develop a model for Bogges-5H well. The available laboratory measurements and published data were analyzed to determine the gas adsorption characteristics and the shale compressibility. The impact of the shale compressibility was then incorporated in the model by developing multipliers for different compressibility components, i.e., fissure, matrix, and hydraulic fracture as function of net stress. A hydraulic fracture model was then coupled with the reservoir model. The combined model was employed to investigate the impact of fluid type, stress shadow, and stage spacing on proppant transport and the gas production. The model’s credibility was confirmed by a close match between the actual and predicted production. The fracture heights induced by all the fluids remained within the pay zone and the entire fracture height contributed to the production. The High Viscosity Friction Reducer (HVFR) resulted in relatively larger fracture volume (increased fracture height) as compared to the Slickwater leading to improved productivity. The crosslinked gels also improved the productivity but were found to be inferior to HVFR. Stress shadow was found to influence the proppant transport and to impact the hydraulic fracture properties and gas production adversely. The adverse impact of the stress shadow on the production is more pronounced during early production due to higher production rates. The findings in this study can be used for fracture treatment design in the Marcellus shale by optimum fluid selection and the stage spacing to reduce the impact of the stress shadow.
{"title":"Impact of Different Fracture Fluid and Stress Shadow on Productivity of the Multi-Stage Fractured Marcellus Shale Horizontal Wells","authors":"Mohammed El sgher, K. Aminian, Vida Matey-Korley, S. Ameri","doi":"10.2118/218094-ms","DOIUrl":"https://doi.org/10.2118/218094-ms","url":null,"abstract":"\u0000 This study investigates the effect of fluid type and stress shadow on proppant transport and the productivity of a multi-stage fractured Marcellus Shale horizontal well. Additionally, the relation between stress shadow and effective stress is studies to optimize fracture effectiveness. This study’s findings can be compared with similar study performed on a different Marcellus shale well. Furthermore, the extent to which various fracture properties contribute to production is evaluated. The available core plugs measurements, well logs, and the image logs were analyzed to determine the shale petrophysical and geomechanical properties including natural fracture (fissure) distribution to develop a model for Bogges-5H well. The available laboratory measurements and published data were analyzed to determine the gas adsorption characteristics and the shale compressibility. The impact of the shale compressibility was then incorporated in the model by developing multipliers for different compressibility components, i.e., fissure, matrix, and hydraulic fracture as function of net stress. A hydraulic fracture model was then coupled with the reservoir model. The combined model was employed to investigate the impact of fluid type, stress shadow, and stage spacing on proppant transport and the gas production.\u0000 The model’s credibility was confirmed by a close match between the actual and predicted production. The fracture heights induced by all the fluids remained within the pay zone and the entire fracture height contributed to the production. The High Viscosity Friction Reducer (HVFR) resulted in relatively larger fracture volume (increased fracture height) as compared to the Slickwater leading to improved productivity. The crosslinked gels also improved the productivity but were found to be inferior to HVFR. Stress shadow was found to influence the proppant transport and to impact the hydraulic fracture properties and gas production adversely. The adverse impact of the stress shadow on the production is more pronounced during early production due to higher production rates. The findings in this study can be used for fracture treatment design in the Marcellus shale by optimum fluid selection and the stage spacing to reduce the impact of the stress shadow.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"24 S54","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395201","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}
R. Sinha, P. Songchitruksa, A. Ambade, S. Ramachandran, V. Ramanathan
Engineering resources are stretched in a field with large-scale operations. Well performance issues are often overlooked, given the high number of wells generating a large volume of data. We developed an advanced intelligent surveillance system to detect common field problems and constraints faster, thereby reducing the time to analyze and diagnose events contributing to well underperformance and reducing the overall time for field engineers to act. Combining industry expertise with data science techniques and machine learning, a series of workflows were constructed to detect well constraints proactively. The well constraints included hydrate formation, crown valve issues, water-cut increase, flowline blockage, wellhead valve malfunction, scale formation, and nonflowing wells. A detection rate of at least 88% and an accuracy of at least 80% were achieved for all the constraint categories for which the models were built. Most labeled events were detected successfully, and the models also produced several new events in the historical data that were not documented through regular manual analysis, later verified to be genuine well constraints. The underperformance conditions in the study were identified as small changes in well behavior that occur through time and are difficult to detect with a non-digital process, even in trained teams, with human surveillance limitations and errors. The system drastically reduced the response time for taking action in the field, giving operators considerable reduction in well downtime and hydrocarbon production. Several machine learning classification models were evaluated, including regression-based and tree-based techniques to detect real-time operational constraints. A logistic classification model was selected for its strength in interpretability, feature evaluation using statistical confidence, real-time execution efficiency, and robust model implementation. Clues in data patterns assisted in the data labeling process by analyzing the historical time-series data and iteratively verifying with the subject matter experts. Feature engineering techniques were used in both time and frequency domains in a machine learning technique that generates output in terms of event probabilities.
{"title":"Real-Time Well Constraint Detection Using an Intelligent Surveillance System","authors":"R. Sinha, P. Songchitruksa, A. Ambade, S. Ramachandran, V. Ramanathan","doi":"10.2118/218043-ms","DOIUrl":"https://doi.org/10.2118/218043-ms","url":null,"abstract":"\u0000 Engineering resources are stretched in a field with large-scale operations. Well performance issues are often overlooked, given the high number of wells generating a large volume of data. We developed an advanced intelligent surveillance system to detect common field problems and constraints faster, thereby reducing the time to analyze and diagnose events contributing to well underperformance and reducing the overall time for field engineers to act.\u0000 Combining industry expertise with data science techniques and machine learning, a series of workflows were constructed to detect well constraints proactively. The well constraints included hydrate formation, crown valve issues, water-cut increase, flowline blockage, wellhead valve malfunction, scale formation, and nonflowing wells. A detection rate of at least 88% and an accuracy of at least 80% were achieved for all the constraint categories for which the models were built. Most labeled events were detected successfully, and the models also produced several new events in the historical data that were not documented through regular manual analysis, later verified to be genuine well constraints. The underperformance conditions in the study were identified as small changes in well behavior that occur through time and are difficult to detect with a non-digital process, even in trained teams, with human surveillance limitations and errors. The system drastically reduced the response time for taking action in the field, giving operators considerable reduction in well downtime and hydrocarbon production.\u0000 Several machine learning classification models were evaluated, including regression-based and tree-based techniques to detect real-time operational constraints. A logistic classification model was selected for its strength in interpretability, feature evaluation using statistical confidence, real-time execution efficiency, and robust model implementation. Clues in data patterns assisted in the data labeling process by analyzing the historical time-series data and iteratively verifying with the subject matter experts. Feature engineering techniques were used in both time and frequency domains in a machine learning technique that generates output in terms of event probabilities.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"47 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284812","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 safe and cost-effective method of stimulating a multi-zone hydrocarbon producing well is presented whereby a tool containing dry chemical is deployed downhole via wireline. An extended exothermic reaction is initiated downhole which generates acid vapour at a target depth in front of the perforated interval. This method allows for each interval to be uniquely treated with specific acid blends and order of operations. A typical well in the field is characterized as a vertical oil producing well with two existing perforated intervals. The top interval is a 3½ foot perforated interval in the Worsley Dolomite with a permeability of 500 - 1000 mD and 40 - 45% porosity. Approximately 50 feet below is a 3 ½ foot perforated Worsley Siltstone interval with 18-20% porosity and permeability of 5 - 10 mD. The 5 ½" 14 lbs/ft cemented production casing is set at approximately 3000 ft. Prior to acidizing, a workover operation was completed where the 2 7/8" tubing was pulled. The order of operations was to first perforate a new 20-foot interval in the Montney that was 70 feet below the Worsley Siltstone. Subsequently, the tightest interval – the Worsley Siltstone – was then treated using an HCl tool deployed via wireline which acted as a pre-flush treatment. This removed any existing scale and provided an HCl rich environment to minimize the risk or precipitation of CaF2 when later acidizing with Mud Acid. After the HCl pre-flush, an HCl/HF tool was then deployed. The next interval was the Worsley Dolomite which was treated with HCl followed by the newly perforated 20-foot Montney interval which was also treated with HCl. This entire operation is completed in 8 hours. Prior to treatment, the candidate wells were producing on average 6 bbl/day and had shown a declining trend over a period of several years. Prior treatments were to bullhead 15% HCl acid and it was believed that the acid was not all going to the desired zone. Using the new method, a total of 7 wells were treated - one well per day - and the average increase in production increase was 342% approximately 60 days post-treatment. The production increase was sustained with wells maintaining an average increase in production of 183% approximately 9 months post-treatment. This method of acidizing has supplanted the previous acidizing method - bullheading of 15% HCl - due to its sustained production enhancement and cost-effectiveness.
{"title":"Targeted Acid Stimulation Technique for Production Enhancement – A Montney Case Study","authors":"F. T. Smith, Z. Ramji","doi":"10.2118/218081-ms","DOIUrl":"https://doi.org/10.2118/218081-ms","url":null,"abstract":"\u0000 A safe and cost-effective method of stimulating a multi-zone hydrocarbon producing well is presented whereby a tool containing dry chemical is deployed downhole via wireline. An extended exothermic reaction is initiated downhole which generates acid vapour at a target depth in front of the perforated interval. This method allows for each interval to be uniquely treated with specific acid blends and order of operations.\u0000 A typical well in the field is characterized as a vertical oil producing well with two existing perforated intervals. The top interval is a 3½ foot perforated interval in the Worsley Dolomite with a permeability of 500 - 1000 mD and 40 - 45% porosity. Approximately 50 feet below is a 3 ½ foot perforated Worsley Siltstone interval with 18-20% porosity and permeability of 5 - 10 mD. The 5 ½\" 14 lbs/ft cemented production casing is set at approximately 3000 ft.\u0000 Prior to acidizing, a workover operation was completed where the 2 7/8\" tubing was pulled. The order of operations was to first perforate a new 20-foot interval in the Montney that was 70 feet below the Worsley Siltstone. Subsequently, the tightest interval – the Worsley Siltstone – was then treated using an HCl tool deployed via wireline which acted as a pre-flush treatment. This removed any existing scale and provided an HCl rich environment to minimize the risk or precipitation of CaF2 when later acidizing with Mud Acid. After the HCl pre-flush, an HCl/HF tool was then deployed. The next interval was the Worsley Dolomite which was treated with HCl followed by the newly perforated 20-foot Montney interval which was also treated with HCl. This entire operation is completed in 8 hours.\u0000 Prior to treatment, the candidate wells were producing on average 6 bbl/day and had shown a declining trend over a period of several years. Prior treatments were to bullhead 15% HCl acid and it was believed that the acid was not all going to the desired zone. Using the new method, a total of 7 wells were treated - one well per day - and the average increase in production increase was 342% approximately 60 days post-treatment. The production increase was sustained with wells maintaining an average increase in production of 183% approximately 9 months post-treatment.\u0000 This method of acidizing has supplanted the previous acidizing method - bullheading of 15% HCl - due to its sustained production enhancement and cost-effectiveness.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395782","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 research investigates the phase behavior of multicomponent diluent and bitumen mixtures, providing experimental data essential for bitumen recovery and pipeline transportation. Using a custom-made experimental setup, including a high-pressure and high-temperature rocking PVT cell, densitometer, viscometer, and data acquisition system, the study analyzes homogenous mixtures and liquid-liquid equilibrium (LLE). Thermophysical properties, such as viscosity and density, are measured. The results reveal that a critical volume fraction of 0.7 of the multicomponent solvent studied leads to a phase transition from homogeneity (single-phase liquid) to two distinct liquid phases. Liquid-liquid equilibrium analysis at different solvent concentrations and temperatures demonstrates the significant impact of diluent on bitumen properties. This study addresses a gap in existing experimental data, offering crucial insights into solvent-aided bitumen recovery and pipeline transportation. It contributes to fostering more efficient and sustainable practices in the oil and bitumen industries.
{"title":"Phase Behavior Analysis of Multicomponent Diluent and Bitumen Mixtures: Applications in In-Situ Extraction and Pipeline Transportation","authors":"Mohammad Shah Faisal Khan, Hassan Hassanzadeh","doi":"10.2118/218063-ms","DOIUrl":"https://doi.org/10.2118/218063-ms","url":null,"abstract":"\u0000 This research investigates the phase behavior of multicomponent diluent and bitumen mixtures, providing experimental data essential for bitumen recovery and pipeline transportation. Using a custom-made experimental setup, including a high-pressure and high-temperature rocking PVT cell, densitometer, viscometer, and data acquisition system, the study analyzes homogenous mixtures and liquid-liquid equilibrium (LLE). Thermophysical properties, such as viscosity and density, are measured. The results reveal that a critical volume fraction of 0.7 of the multicomponent solvent studied leads to a phase transition from homogeneity (single-phase liquid) to two distinct liquid phases. Liquid-liquid equilibrium analysis at different solvent concentrations and temperatures demonstrates the significant impact of diluent on bitumen properties. This study addresses a gap in existing experimental data, offering crucial insights into solvent-aided bitumen recovery and pipeline transportation. It contributes to fostering more efficient and sustainable practices in the oil and bitumen industries.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"41 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284961","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}
Although foamy oil phenomenon has been considered as the key factor that dominates heavy oil recovery, the existing models cannot be used to accurately quantify gas exsolution dynamics in foamy oil under various conditions due to the inherent physics and complex flow behaviour. In this study, experimental and theoretical techniques have been developed to quantify gas exsolution dynamics of CO2/CH4-heavy oil systems while considering gas bubble nucleation mobilization, and binary coalescence. Experimentally, constant composition expansion (CCE) tests were performed with a sealed PVT apparatus for the CO2/CH4-heavy oil systems to induce foamy oil behaviour by gradually depleting pressure at a constant temperature, during which the pressures and volume changes were monitored and recorded continuously. Theoretically, the Fick's law, equation of state, classical nucleation theory, and population balance equation have been integrated to describe the gas exsolution dynamics, during which gas bubbles are discretized with the fixed-pivot technique. The gas bubble number and size distribution in the induced foamy oil can then be determined once the deviations between the measured and calculated parameters, including liquid volume and pseudo-bubble point pressure, have been minimized with the genetic algorithm. For both CO2- and CH4-heavy oil systems, not only can a reducing pressure depletion rate or an increasing temperature result in a higher pseudo-bubblepoint pressure, but also gas bubble growth is strongly dependent on both temperature and diffusion of a gas component in heavy oil, while increasing the solvent concentration in the heavy oil tends to hinder the gas bubble nucleation and mitigation due to the higher pressure set for the experiments. During the generation of foamy oil, a higher temperature reduces heavy oil viscosity to accelerate the diffusion process, positively contributing to the gas bubble nucleation, binary coalescence, and bubble mobilization, respectively. Compared with CO2, CH4 induces a stronger and more stable foamy oil, illustrating that, at a lower temperature, foamy oil is more stable with more dispersed gas bubbles. In this study, the newly developed theoretical techniques are able to reproduce gas exsolution dynamics at the bubble level, allowing us to seamlessly integrate them with any reservoir simulators to not only accurately characterize foamy oil behaviour, but also evaluate the associated recovery performance.
{"title":"Quantification of Gas Exsolution Dynamics for CO2/CH4-Heavy Oil Systems with Population Balance Equations","authors":"Xiaomeng Dong, Zulong Zhao, Daoyong Yang, Na Jia","doi":"10.2118/218070-ms","DOIUrl":"https://doi.org/10.2118/218070-ms","url":null,"abstract":"\u0000 Although foamy oil phenomenon has been considered as the key factor that dominates heavy oil recovery, the existing models cannot be used to accurately quantify gas exsolution dynamics in foamy oil under various conditions due to the inherent physics and complex flow behaviour. In this study, experimental and theoretical techniques have been developed to quantify gas exsolution dynamics of CO2/CH4-heavy oil systems while considering gas bubble nucleation mobilization, and binary coalescence. Experimentally, constant composition expansion (CCE) tests were performed with a sealed PVT apparatus for the CO2/CH4-heavy oil systems to induce foamy oil behaviour by gradually depleting pressure at a constant temperature, during which the pressures and volume changes were monitored and recorded continuously. Theoretically, the Fick's law, equation of state, classical nucleation theory, and population balance equation have been integrated to describe the gas exsolution dynamics, during which gas bubbles are discretized with the fixed-pivot technique. The gas bubble number and size distribution in the induced foamy oil can then be determined once the deviations between the measured and calculated parameters, including liquid volume and pseudo-bubble point pressure, have been minimized with the genetic algorithm. For both CO2- and CH4-heavy oil systems, not only can a reducing pressure depletion rate or an increasing temperature result in a higher pseudo-bubblepoint pressure, but also gas bubble growth is strongly dependent on both temperature and diffusion of a gas component in heavy oil, while increasing the solvent concentration in the heavy oil tends to hinder the gas bubble nucleation and mitigation due to the higher pressure set for the experiments. During the generation of foamy oil, a higher temperature reduces heavy oil viscosity to accelerate the diffusion process, positively contributing to the gas bubble nucleation, binary coalescence, and bubble mobilization, respectively. Compared with CO2, CH4 induces a stronger and more stable foamy oil, illustrating that, at a lower temperature, foamy oil is more stable with more dispersed gas bubbles. In this study, the newly developed theoretical techniques are able to reproduce gas exsolution dynamics at the bubble level, allowing us to seamlessly integrate them with any reservoir simulators to not only accurately characterize foamy oil behaviour, but also evaluate the associated recovery performance.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"50 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395608","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}
Hydrate formation is a flow assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In Water-Alternating-Gas (WAG) operations, hydrates can form within the injection wells when switching from water-to-gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations. Compositional changes, temperature, and required thermodynamic inhibitor are evaluated within the injector well where hydrate formation is likely. The simulation study is conducted on a representative offshore field at a seabed depth of 124 m and temperature of 3ºC. The dynamic multiphase flow simulator was used for the WAG simulation and fluid modeling. The subcooling is evaluated to detect potential hydrate formation. After determining the hydrate risk zones for water-to-gas and gas-to-water operations through detecting the regions with positive values of subcooling where the fluids can be exposed to hydrate formation, the effects of gas composition (CO2 content) change, and methanol injection on the subcooling profile are evaluated. Simulation results indicated a higher risk of hydrate formation after the start of water injection in gas-to-water during an offshore injection well changeover operation due to slower fluid displacement. In both cases, after starting the injection operation the subcooling is reduced significantly for the entire well. However, in the water-to-gas changeover, the sections of the well that had water and gas were outside the hydrate formation region after 1 hour of gas injection. For a water injection rate of 2,300 m3/day, 1 MSm3/d of gas was adequate to displace the entire water column in the well into the reservoir in the water-to-gas changeover operation. For gas-to-water changeover operation, full displacement of the gas occurred after 11 hours and 9 hours for the base natural gas case and the natural water with NG (CO2 44 wt%) case, respectively. Methanol slug injection (5 m3) at the end of the water injection inhibited hydrate formation for the entire length of the well. Fluid model simulations indicate that changing the CO2 composition (5-44 wt%) has a noticeable effect on the phase envelope and shifts the hydrate curve up to 2ºC. Few previous studies have investigated WAG changeover operations with the effect of CO2 and methanol concentrations on hydrate formation. One study found hydrate formation risk in water-to-gas operations based on onshore well with no attention to the impact of thermodynamic inhibitors and gas composition. This study investigates the hydrate formation risk, the impact of natural gas (NG) composition (CO2, 5-44 wt%), and the applicability of methanol in WAG changeover operations in an offshore well.
{"title":"Investigating the Effect of Carbon Dioxide Concentration on Hydrate Formation Risk from Water Alternating Gas (WAG) Changeover Operations","authors":"F. S. Moghaddam, M. A. Abdi, L. A. James","doi":"10.2118/218101-ms","DOIUrl":"https://doi.org/10.2118/218101-ms","url":null,"abstract":"\u0000 Hydrate formation is a flow assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In Water-Alternating-Gas (WAG) operations, hydrates can form within the injection wells when switching from water-to-gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations. Compositional changes, temperature, and required thermodynamic inhibitor are evaluated within the injector well where hydrate formation is likely.\u0000 The simulation study is conducted on a representative offshore field at a seabed depth of 124 m and temperature of 3ºC. The dynamic multiphase flow simulator was used for the WAG simulation and fluid modeling. The subcooling is evaluated to detect potential hydrate formation. After determining the hydrate risk zones for water-to-gas and gas-to-water operations through detecting the regions with positive values of subcooling where the fluids can be exposed to hydrate formation, the effects of gas composition (CO2 content) change, and methanol injection on the subcooling profile are evaluated.\u0000 Simulation results indicated a higher risk of hydrate formation after the start of water injection in gas-to-water during an offshore injection well changeover operation due to slower fluid displacement. In both cases, after starting the injection operation the subcooling is reduced significantly for the entire well. However, in the water-to-gas changeover, the sections of the well that had water and gas were outside the hydrate formation region after 1 hour of gas injection. For a water injection rate of 2,300 m3/day, 1 MSm3/d of gas was adequate to displace the entire water column in the well into the reservoir in the water-to-gas changeover operation. For gas-to-water changeover operation, full displacement of the gas occurred after 11 hours and 9 hours for the base natural gas case and the natural water with NG (CO2 44 wt%) case, respectively. Methanol slug injection (5 m3) at the end of the water injection inhibited hydrate formation for the entire length of the well. Fluid model simulations indicate that changing the CO2 composition (5-44 wt%) has a noticeable effect on the phase envelope and shifts the hydrate curve up to 2ºC.\u0000 Few previous studies have investigated WAG changeover operations with the effect of CO2 and methanol concentrations on hydrate formation. One study found hydrate formation risk in water-to-gas operations based on onshore well with no attention to the impact of thermodynamic inhibitors and gas composition. This study investigates the hydrate formation risk, the impact of natural gas (NG) composition (CO2, 5-44 wt%), and the applicability of methanol in WAG changeover operations in an offshore well.","PeriodicalId":517551,"journal":{"name":"Day 2 Thu, March 14, 2024","volume":"90 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284749","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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