S. Asel, Abdullah M. Al Moajil, B. Al-Harbi, Sajjad Al Darweesh
Multistage Fracturing (MSF) completions have been extensively used as an economical intervention means to handle extreme downhole environment. To have adequate Injectivity during hydraulic fracturing (HF), sand face permeability should be exposed to minimum formation damage. Impaired injectivity is caused by a mechanical obstruction across wellbore, tight formations (low permeability) and high heterogeneity or invaded particulates by Drill-In-Fluid (DIF) that damaged the formation. Many causes were suspected such as formation heterogeneity, false indication of completion port opening, and damage to the sand face due to drilling filter cake. Solvent treatments, acid wash and tubular slotting are the most reasonable remedies to this issue, adding more cost to the operating company. The objective of this study is to present technical procedures and methodologies followed to investigate impaired injectivity associated with MSF completions. Results and recommendations provide remedial recipes and optimized drilling and production operating procedures. Therefore, realizing a significant cost saving for operating companies. X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), and Environmental Scanning Electron Microscope (ESEM) techniques were used to analyze solid samples. HP/HT aging cells were used to conduct solubility testing of filter cake and typical barite/oil-based sludge sample. HP/HT filter press was used to study the effect of time on filter cake build-up at 300°F. HCl acid showed low solubility for typical oil-based drilling fluid sludge at 310°F. Mutual solvents dissolved the sludge partially at 300°F (e.g. ~40wt% solubility). DTPA and EDTA-based chelating agents showed higher dissolution power compared to the HCl solutions. The addition of mutual solvent to the tested chemicals increased the solubility of the sludge. Among tested chemicals, 90 % DTPA and 5 % mutual solvent provided the higher solubility. High filtration rate was noticed during HP/HT filtration test. The thickness of the filter cake increased significantly as a consequence of filtration/soaking time (e.g., up to a week). Therefore, to avoid filter cake build up and the problems associated with that, the filter cake should be removed immediately after the drilling operations.
{"title":"Drilling Fluid Impact on Injectivity During Multistage Fracturing in Horizontal Wells","authors":"S. Asel, Abdullah M. Al Moajil, B. Al-Harbi, Sajjad Al Darweesh","doi":"10.2118/195302-MS","DOIUrl":"https://doi.org/10.2118/195302-MS","url":null,"abstract":"\u0000 Multistage Fracturing (MSF) completions have been extensively used as an economical intervention means to handle extreme downhole environment. To have adequate Injectivity during hydraulic fracturing (HF), sand face permeability should be exposed to minimum formation damage. Impaired injectivity is caused by a mechanical obstruction across wellbore, tight formations (low permeability) and high heterogeneity or invaded particulates by Drill-In-Fluid (DIF) that damaged the formation. Many causes were suspected such as formation heterogeneity, false indication of completion port opening, and damage to the sand face due to drilling filter cake. Solvent treatments, acid wash and tubular slotting are the most reasonable remedies to this issue, adding more cost to the operating company. The objective of this study is to present technical procedures and methodologies followed to investigate impaired injectivity associated with MSF completions. Results and recommendations provide remedial recipes and optimized drilling and production operating procedures. Therefore, realizing a significant cost saving for operating companies.\u0000 X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), and Environmental Scanning Electron Microscope (ESEM) techniques were used to analyze solid samples. HP/HT aging cells were used to conduct solubility testing of filter cake and typical barite/oil-based sludge sample. HP/HT filter press was used to study the effect of time on filter cake build-up at 300°F.\u0000 HCl acid showed low solubility for typical oil-based drilling fluid sludge at 310°F. Mutual solvents dissolved the sludge partially at 300°F (e.g. ~40wt% solubility). DTPA and EDTA-based chelating agents showed higher dissolution power compared to the HCl solutions. The addition of mutual solvent to the tested chemicals increased the solubility of the sludge. Among tested chemicals, 90 % DTPA and 5 % mutual solvent provided the higher solubility. High filtration rate was noticed during HP/HT filtration test. The thickness of the filter cake increased significantly as a consequence of filtration/soaking time (e.g., up to a week). Therefore, to avoid filter cake build up and the problems associated with that, the filter cake should be removed immediately after the drilling operations.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124366303","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}
Cristhian Camilo Tello Bahamon, G. Mora, T. Acosta, German Alberto Manrique, D. Quintero
This paper presents the successful implementation of an interwell tracer program performed in a multilayered reservoir with mature waterflooding. The objectives of the program are to evaluate water channeling in a high water cut field and, assess sweep efficiency improvements in an EOR pilot test. An extensive methodology was prepared to ensure the quality of the program. The first stage followed the screening of areas and reservoir layers with underperforming waterflooding. After that, the design stage included a selection of tracer available in the market, volume calculation and breakthrough time simulations. The execution plan defined the optimum injection rates, equipment and lab tests requirements for the monitoring and field sampling schedule. The results were being recorded in a monthly progress report and analyzed by a technical team in charge of the project. Interwell tracers made possible to confirm water channeling issues and provided information about the severity of preferential flow using the breakthrough times obtained for each reservoir layer. It was also possible to observe how changes in injection rate impacted the recovery of the tracers, creating different flow patterns at different flow rates. The six-month monitoring ended with the estimation of channel volume to design water conformance treatments. In addition, the findings from the interwell tracer conducted in the EOR pilot test showed an increase in the breakthrough time after three years of polymer flooding and, a change in flow patterns that allowed the displacement of previously bypassed oil. These results are interpreted as a measurable improvement of sweep efficiency and served as input to appraise the performance of the pilot test.
{"title":"Understanding Flow Through Interwell Tracers","authors":"Cristhian Camilo Tello Bahamon, G. Mora, T. Acosta, German Alberto Manrique, D. Quintero","doi":"10.2118/195251-MS","DOIUrl":"https://doi.org/10.2118/195251-MS","url":null,"abstract":"\u0000 This paper presents the successful implementation of an interwell tracer program performed in a multilayered reservoir with mature waterflooding. The objectives of the program are to evaluate water channeling in a high water cut field and, assess sweep efficiency improvements in an EOR pilot test. An extensive methodology was prepared to ensure the quality of the program. The first stage followed the screening of areas and reservoir layers with underperforming waterflooding. After that, the design stage included a selection of tracer available in the market, volume calculation and breakthrough time simulations. The execution plan defined the optimum injection rates, equipment and lab tests requirements for the monitoring and field sampling schedule. The results were being recorded in a monthly progress report and analyzed by a technical team in charge of the project. Interwell tracers made possible to confirm water channeling issues and provided information about the severity of preferential flow using the breakthrough times obtained for each reservoir layer. It was also possible to observe how changes in injection rate impacted the recovery of the tracers, creating different flow patterns at different flow rates. The six-month monitoring ended with the estimation of channel volume to design water conformance treatments. In addition, the findings from the interwell tracer conducted in the EOR pilot test showed an increase in the breakthrough time after three years of polymer flooding and, a change in flow patterns that allowed the displacement of previously bypassed oil. These results are interpreted as a measurable improvement of sweep efficiency and served as input to appraise the performance of the pilot test.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121830376","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}
Heat generation in the reservoir by means of electromagnetic wave stimulation offers innate advantage with efficient energy introduction. Transmissibility of heavy oil and bitumen are predicated on decreased viscosity through temperature rise, which makes microwave heating a plausible candidate. This study focuses on identifying the components of the crude oil which primarily contribute to heat generation under the influence of the microwave. Pinpointing what makes the oil a more effective microwave receptor enables the optimization of desirable traits in the oil phase. Three different oil samples were selected due to variations in both physical and dielectric properties. Fractionations were then performed on each oil to isolate the contribution of each SARA (saturates, aromatics, resins, and asphaltenes) constituent. Dielectric constant and loss index, which together represent complex permittivity, were measured by utilization of a vector network analyzer (VNA) with a dielectric probe. Complex permittivity of both the bulk oil as well as each fraction were measured for all three oil samples. Also, investigation into asphaltenes behavior in the oil, either precipitated or dispersed, was performed by introducing varying dosages of both precipitating agents (nC5, nC7) and a dispersant (toluene). Within the oil phase, the mutual attraction that is realized by the more polar components, namely the resins and asphaltenes, creates complexities in the absorption behavior. Net cancellation of the individual polarity is evidenced by the non-additive nature of the deasphalted oil and asphaltenes. The attraction between the resins and asphaltenes is further illuminated by inspection of the dielectric response in the presence of the precipitating agents. Removal of asphaltenes through precipitation corresponds to the freeing of interacted resins. The contribution in polarity of the previously cancelled resins is evidenced by an increase in the dielectric constant with increasing precipitating dosage. Both oil C2 and C3 achieve the identified behavior stemming from an asphaltene weight percent comparable to that of the resins. However, upon analysis of the oil C1, the opposite trend is achieved. Unique to oil C1 is a very large weight percent of asphaltenes. Therefore, the oil has excess asphaltenes which aren't interacting with the resins. Precipitation preferentially occurs from those asphaltenes not being interacted as they are relatively less stable. Net cancellation of all resins remains untouched and no resins are freed as a function of the precipitation for oil C1. The foundational impact of polarity on absorption characteristics provides the potential to investigate the efficacy of microwave introduction specific to each fractionation. Experimental results from dielectric property measurements showed that the polar fractions of the crude oil, resins and asphaltenes, heavily influence the effectiveness of microwave heating. For the first time, the
{"title":"Effect of Crude Oil Composition on Microwave Absorption of Heavy Oils","authors":"H. Liao, M. Morte, B. Hascakir","doi":"10.2118/195263-MS","DOIUrl":"https://doi.org/10.2118/195263-MS","url":null,"abstract":"\u0000 Heat generation in the reservoir by means of electromagnetic wave stimulation offers innate advantage with efficient energy introduction. Transmissibility of heavy oil and bitumen are predicated on decreased viscosity through temperature rise, which makes microwave heating a plausible candidate. This study focuses on identifying the components of the crude oil which primarily contribute to heat generation under the influence of the microwave. Pinpointing what makes the oil a more effective microwave receptor enables the optimization of desirable traits in the oil phase.\u0000 Three different oil samples were selected due to variations in both physical and dielectric properties. Fractionations were then performed on each oil to isolate the contribution of each SARA (saturates, aromatics, resins, and asphaltenes) constituent. Dielectric constant and loss index, which together represent complex permittivity, were measured by utilization of a vector network analyzer (VNA) with a dielectric probe. Complex permittivity of both the bulk oil as well as each fraction were measured for all three oil samples. Also, investigation into asphaltenes behavior in the oil, either precipitated or dispersed, was performed by introducing varying dosages of both precipitating agents (nC5, nC7) and a dispersant (toluene).\u0000 Within the oil phase, the mutual attraction that is realized by the more polar components, namely the resins and asphaltenes, creates complexities in the absorption behavior. Net cancellation of the individual polarity is evidenced by the non-additive nature of the deasphalted oil and asphaltenes. The attraction between the resins and asphaltenes is further illuminated by inspection of the dielectric response in the presence of the precipitating agents. Removal of asphaltenes through precipitation corresponds to the freeing of interacted resins. The contribution in polarity of the previously cancelled resins is evidenced by an increase in the dielectric constant with increasing precipitating dosage. Both oil C2 and C3 achieve the identified behavior stemming from an asphaltene weight percent comparable to that of the resins. However, upon analysis of the oil C1, the opposite trend is achieved. Unique to oil C1 is a very large weight percent of asphaltenes. Therefore, the oil has excess asphaltenes which aren't interacting with the resins. Precipitation preferentially occurs from those asphaltenes not being interacted as they are relatively less stable. Net cancellation of all resins remains untouched and no resins are freed as a function of the precipitation for oil C1.\u0000 The foundational impact of polarity on absorption characteristics provides the potential to investigate the efficacy of microwave introduction specific to each fractionation. Experimental results from dielectric property measurements showed that the polar fractions of the crude oil, resins and asphaltenes, heavily influence the effectiveness of microwave heating. For the first time, the","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127413897","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The displacement of viscous oils typically involves unstable immiscible flow. The microscopic and volumetric efficiency is further exacerbated if the reservoir is oil-wet and heterogeneous, respectively. The goal of this work is to systematically compare the performance of secondary vs. tertiary polymer flooding for viscous oil recovery in an oil-wet 2D, layered, heterogeneous system. It focuses on performing flow visualization to capture the effect of cross-flow and viscous fingering in both modes. First, contact angle experiments were performed to ensure that the reservoir crude oil results in oil-wet sand. Second, rheological analysis of HPAM polymer solution was performed to find the optimal injection concentration. Third, oil displacement experiments were performed in an in-house, custom-built 2D sandpack with the front face made of a transparent acrylic sheet for flow visualization. It was packed with two communicating layers of silica sand — bottom layer with 20-30 mesh and a top layer with 100-120 mesh, which resulted in a permeability contrast of 8:1. The system was vacuum-saturated with a viscous crude oil with a viscosity of 157 cp. Polymer floods were conducted in secondary and tertiary modes and the oil displacement profiles were continuously monitored using a camera. At the end of the experiments, the sandpacks were cut in 16-equal zones and were analyzed for the amount of crude oil using UV-Spectroscopy to quantify the residual oil saturation achieved in each zone. Finally, the results were compared with analogous floods in 1D sandpacks to understand the effect of heterogeneity. The contact angle experiments revealed that the reservoir crude oil used in the present work resulted in highly oil-wet sand after aging. In the oil displacement experiments in the layered sandpack, the secondary waterflood recovery after 1 PV was low (∼25% OOIP) due to channeling in the bottom high-permeability region, leaving the top low-permeability region completely unswept. Tertiary polymer flooding leads to improvement in sweep efficiency in both regions. It resulted in an incremental oil recovery of 53% OOIP with an ultimate recovery of 78% OOIP. Conversely, polymer flooding in secondary mode resulted in 46% OOIP in 1 PV injection. But the overall recovery was 69 % OOIP which was less than the tertiary mode. Different flow phenomena, such as, cross-flow, gravity segregation, and viscous fingering, were observed in these visualization experiments.
{"title":"Polymer Flooding in Oil-Wet, 2D Heterogeneous Porous Media","authors":"Robin Singh, Haofeng Song, K. Mohanty","doi":"10.2118/195340-MS","DOIUrl":"https://doi.org/10.2118/195340-MS","url":null,"abstract":"\u0000 The displacement of viscous oils typically involves unstable immiscible flow. The microscopic and volumetric efficiency is further exacerbated if the reservoir is oil-wet and heterogeneous, respectively. The goal of this work is to systematically compare the performance of secondary vs. tertiary polymer flooding for viscous oil recovery in an oil-wet 2D, layered, heterogeneous system. It focuses on performing flow visualization to capture the effect of cross-flow and viscous fingering in both modes. First, contact angle experiments were performed to ensure that the reservoir crude oil results in oil-wet sand. Second, rheological analysis of HPAM polymer solution was performed to find the optimal injection concentration. Third, oil displacement experiments were performed in an in-house, custom-built 2D sandpack with the front face made of a transparent acrylic sheet for flow visualization. It was packed with two communicating layers of silica sand — bottom layer with 20-30 mesh and a top layer with 100-120 mesh, which resulted in a permeability contrast of 8:1. The system was vacuum-saturated with a viscous crude oil with a viscosity of 157 cp. Polymer floods were conducted in secondary and tertiary modes and the oil displacement profiles were continuously monitored using a camera. At the end of the experiments, the sandpacks were cut in 16-equal zones and were analyzed for the amount of crude oil using UV-Spectroscopy to quantify the residual oil saturation achieved in each zone. Finally, the results were compared with analogous floods in 1D sandpacks to understand the effect of heterogeneity. The contact angle experiments revealed that the reservoir crude oil used in the present work resulted in highly oil-wet sand after aging. In the oil displacement experiments in the layered sandpack, the secondary waterflood recovery after 1 PV was low (∼25% OOIP) due to channeling in the bottom high-permeability region, leaving the top low-permeability region completely unswept. Tertiary polymer flooding leads to improvement in sweep efficiency in both regions. It resulted in an incremental oil recovery of 53% OOIP with an ultimate recovery of 78% OOIP. Conversely, polymer flooding in secondary mode resulted in 46% OOIP in 1 PV injection. But the overall recovery was 69 % OOIP which was less than the tertiary mode. Different flow phenomena, such as, cross-flow, gravity segregation, and viscous fingering, were observed in these visualization experiments.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"119 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116381465","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}
Oliver Chang, Yan Pan, Aysegul Dastan, David Teague, F. Descant
There are on-going efforts in digital transformation in different aspects of hydrocarbon recovery. For well performance surveillance, we have developed the key elements of a Transient Data Surveillance Machine to efficiently process and analyze all transient data from continuous measurements at the wells, allowing for full utilization of the available data. The workflow has been applied at wells in a deep-water oil field in Gulf of Mexico and proved to be effective. We developed Machine Learning (ML) algorithms and techniques to efficiently process and analyze pressure-rate transient data. Following the automatic workflow, K-mean clustering is used to identify shut-in periods, maximum-slope method is used to synchronize pressure and rate data, Supported Vector Machine algorithm combined with Kernel method is used for transient flow-regime recognition, followed by Non-Linear Regression using physical models to estimate reservoir and well properties and assess uncertainty. Through synthetic case and field data testing, we demonstrated that the ML method is tolerant to data noise. Even at 15% of noise level, which is much higher than standard pressure gauge data, the successful rate is 98% in flow-regime identification. However, it is sensitive to data outliers, and we need to include other techniques, such as wavelet data processing, in the workflow. Adding real field data with associated reservoir models that are validated by experts into the training data set could increase the accuracy of pattern recognition 10% more than training with only analytical solutions. The application of our workflow in a deep-water oil field in Gulf of Mexico, which started oil production in 2009 with all wells with permanent downhole pressure gauges, helped to process and analyze transient data from shut-in’s (70% planned transient tests and 30% operation related) efficiently, and derived information about well productivity changes, interference among wells, and permeability reduction due to rock compaction. This enabled continuous well monitoring and effective identification of well productivity issues. The novelty of our Transient Data Surveillance Machine is its capacity in handling huge amounts of dynamic data and its efficiency using real-time data diagnosis for operation decisions and reservoir management.
{"title":"Application of Machine Learning in Transient Surveillance in a Deep-Water Oil Field","authors":"Oliver Chang, Yan Pan, Aysegul Dastan, David Teague, F. Descant","doi":"10.2118/195278-MS","DOIUrl":"https://doi.org/10.2118/195278-MS","url":null,"abstract":"\u0000 There are on-going efforts in digital transformation in different aspects of hydrocarbon recovery. For well performance surveillance, we have developed the key elements of a Transient Data Surveillance Machine to efficiently process and analyze all transient data from continuous measurements at the wells, allowing for full utilization of the available data. The workflow has been applied at wells in a deep-water oil field in Gulf of Mexico and proved to be effective.\u0000 We developed Machine Learning (ML) algorithms and techniques to efficiently process and analyze pressure-rate transient data. Following the automatic workflow, K-mean clustering is used to identify shut-in periods, maximum-slope method is used to synchronize pressure and rate data, Supported Vector Machine algorithm combined with Kernel method is used for transient flow-regime recognition, followed by Non-Linear Regression using physical models to estimate reservoir and well properties and assess uncertainty.\u0000 Through synthetic case and field data testing, we demonstrated that the ML method is tolerant to data noise. Even at 15% of noise level, which is much higher than standard pressure gauge data, the successful rate is 98% in flow-regime identification. However, it is sensitive to data outliers, and we need to include other techniques, such as wavelet data processing, in the workflow. Adding real field data with associated reservoir models that are validated by experts into the training data set could increase the accuracy of pattern recognition 10% more than training with only analytical solutions. The application of our workflow in a deep-water oil field in Gulf of Mexico, which started oil production in 2009 with all wells with permanent downhole pressure gauges, helped to process and analyze transient data from shut-in’s (70% planned transient tests and 30% operation related) efficiently, and derived information about well productivity changes, interference among wells, and permeability reduction due to rock compaction. This enabled continuous well monitoring and effective identification of well productivity issues.\u0000 The novelty of our Transient Data Surveillance Machine is its capacity in handling huge amounts of dynamic data and its efficiency using real-time data diagnosis for operation decisions and reservoir management.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"304 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120881987","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}
With the increase of mature wells, comingled production from multi-zones in long laterals has become more common in recent years. High sand production, wellbore collapse and water invasion from high-pressure aquifers have been observed more frequently. Among these adverse consequences, water invasion is one of the most common issues throughout the production in lateral wells. Various solutions have been introduced to mitigate this, but this paper will focus on an innovative cement retainer which could eliminate the mill out and leave zero debris downhole after the tool functions for zonal water shut off.
{"title":"The Application of Dissolvable Cement Retainer for Remedial Cementing Technique in High Water Production Zone","authors":"Shuo Zhang, Weiyi Wang, L. Zeng, Niketa Chep","doi":"10.2118/195330-MS","DOIUrl":"https://doi.org/10.2118/195330-MS","url":null,"abstract":"\u0000 With the increase of mature wells, comingled production from multi-zones in long laterals has become more common in recent years. High sand production, wellbore collapse and water invasion from high-pressure aquifers have been observed more frequently. Among these adverse consequences, water invasion is one of the most common issues throughout the production in lateral wells. Various solutions have been introduced to mitigate this, but this paper will focus on an innovative cement retainer which could eliminate the mill out and leave zero debris downhole after the tool functions for zonal water shut off.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130081998","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}
Unmanned Vehicles (UV) can be classified by the environment in which they operate. The vehicle may or may not be autonomous. Sea: Unmanned underwater vehicles (UUV),Land: Unmanned surface vehicles (USV)Air: Unmanned aerial vehicles (UAV), popularly known as drones The life cycle of oil and gas fields can be broadly divided into four phases: Exploration & Appraisal, Development, Production, and Decommissioning. Unmanned vehicles are increasingly finding applications in all these four phases. The use of unmanned vehicles in air, sea and land, can minimize exposure of personnel to dangerous environments, monitor the environment, improve efficiency of operations, improve asset integrity, and assist site reconnaissance and data gathering. Key enablers to the recent wide-spread applications of unmanned vehicles in the industry are advances in remote sensing technology, artificial intelligence, data analytics as well as the decreasing costs. Unmanned vehicles and robotics offer opportunities to the oil industry to make a step change to the way we do things. This paper presents an overview of the current and potential applications of the emerging technology of unmanned vehicles in the oil and gas industry.
{"title":"The Growing Role of Unmanned Vehicles in the Oil Industry","authors":"H. Saadawi","doi":"10.2118/195255-MS","DOIUrl":"https://doi.org/10.2118/195255-MS","url":null,"abstract":"\u0000 Unmanned Vehicles (UV) can be classified by the environment in which they operate. The vehicle may or may not be autonomous. Sea: Unmanned underwater vehicles (UUV),Land: Unmanned surface vehicles (USV)Air: Unmanned aerial vehicles (UAV), popularly known as drones\u0000 The life cycle of oil and gas fields can be broadly divided into four phases: Exploration & Appraisal, Development, Production, and Decommissioning. Unmanned vehicles are increasingly finding applications in all these four phases. The use of unmanned vehicles in air, sea and land, can minimize exposure of personnel to dangerous environments, monitor the environment, improve efficiency of operations, improve asset integrity, and assist site reconnaissance and data gathering.\u0000 Key enablers to the recent wide-spread applications of unmanned vehicles in the industry are advances in remote sensing technology, artificial intelligence, data analytics as well as the decreasing costs. Unmanned vehicles and robotics offer opportunities to the oil industry to make a step change to the way we do things.\u0000 This paper presents an overview of the current and potential applications of the emerging technology of unmanned vehicles in the oil and gas industry.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"137 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116411125","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. Abaa, John Yilin-Wang, D. Elsworth, M. Ityokumbul
Improper selection and design of surfactant treatments intended to remove damage aqueous phase trapping often ends up causing other types of formation damage. This is due to our limited understanding of the processes that govern rock-fluid and fluid-fluid interactions between surfactants, fracturing fluid and the formation during invasion and flowback of the injected fluids in the rock matrix. This study focuses on the laboratory investigation of the processes governing multiphase permeability evolution during invasion of fracturing fluids treated with surfactants in low permeability sandstones. Two surfactant chemicals, Triton X-100, a hydrocarbon surfactant and Novec FC-4430, a fluorosurfactant, were used to treat filtrate from slickwater, linear gel and borate crosslinked gel fluids. Multiphase experiments were conducted on sandstones cores flooded with the treated fluids. The experiments consist of steady state gas displacements and pulse decay permeability measurements. The obtained data include gas flow rate, pore volumes of liquid expelled and gas relative permeability curves. Experimental results indicate that treatments with fluorosurfactant improved liquid and gas permeability recovery for all fracturing fluids. Additionally, maximum liquid and gas permeability recovery was achieved when the core was pretreated with fluorosurfactant. Our results show that multiphase permeability evolution with surfactant treatment is driven by wettability alterations rather than reduction in interfacial tension. Multiphase permeability data could be used in modeling of post fracture well performance and formation damage assessment in low permeability sandstones. The new findings will serve as a guide for optimizing fracturing fluid/surfactant treatment in tight gas reservoirs.
{"title":"Multiphase Permeability Evolution in Low Permeability Sandstones from Surfactant-Treated Fractring Fluids","authors":"K. Abaa, John Yilin-Wang, D. Elsworth, M. Ityokumbul","doi":"10.2118/195288-MS","DOIUrl":"https://doi.org/10.2118/195288-MS","url":null,"abstract":"\u0000 Improper selection and design of surfactant treatments intended to remove damage aqueous phase trapping often ends up causing other types of formation damage. This is due to our limited understanding of the processes that govern rock-fluid and fluid-fluid interactions between surfactants, fracturing fluid and the formation during invasion and flowback of the injected fluids in the rock matrix. This study focuses on the laboratory investigation of the processes governing multiphase permeability evolution during invasion of fracturing fluids treated with surfactants in low permeability sandstones.\u0000 Two surfactant chemicals, Triton X-100, a hydrocarbon surfactant and Novec FC-4430, a fluorosurfactant, were used to treat filtrate from slickwater, linear gel and borate crosslinked gel fluids. Multiphase experiments were conducted on sandstones cores flooded with the treated fluids. The experiments consist of steady state gas displacements and pulse decay permeability measurements. The obtained data include gas flow rate, pore volumes of liquid expelled and gas relative permeability curves.\u0000 Experimental results indicate that treatments with fluorosurfactant improved liquid and gas permeability recovery for all fracturing fluids. Additionally, maximum liquid and gas permeability recovery was achieved when the core was pretreated with fluorosurfactant. Our results show that multiphase permeability evolution with surfactant treatment is driven by wettability alterations rather than reduction in interfacial tension.\u0000 Multiphase permeability data could be used in modeling of post fracture well performance and formation damage assessment in low permeability sandstones. The new findings will serve as a guide for optimizing fracturing fluid/surfactant treatment in tight gas reservoirs.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132468261","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}
Temperature monitoring is the most important surveillance in thermal assets, but temperature logging is limited in frequencies and locations. In addition, it is extremely difficult to review all the measured temperature and injection data manually since there are 10,000+ wells in Kern River field. To overcome the limitations, data-driven reservoir temperature models are presented that are built using past temperature logs and steam injection rates of the Kern River field, California. Based on the physics and geologic understanding the reservoir, adequate input features were selected and queried. Data cleanup was conducted to remove erroneous data or fix data errors using statistical tools such as multivariate Gaussian distribution. Voronoi diagram based dynamic injector selection algorithm (DISA) was developed to correctly capture the injectors which impact on temperature changes of a temperature observation well. Based on geologic characteristics of the Kern River, reservoir was divided into two sub-reservoirs, North-East and South-West. Two full field models were developed for predicting maximum and mean temperatures of a heated zone with multi-layer perceptron for both sub-reservoirs using about 120,000 data points from over 25,000 temperature curves measured at 700+ temperature observation wells. To estimate proper model update frequencies and verify the process, three yearly models (models 2015, 2016, and 2017) were built and validated by using one-year future temperature predictions in 2016, 2017, and 2018. For instance, model 2015 was trained with data until the end of 2015 and validated against 2016 data. Maximum temperature prediction r2 of 2017 South-West and North-East models were 0.96 and 0.98, respectively. Model 2017 has been deployed for alerting exception cases automatically and flagging abnormal temperature measurements. Also, the models improve the quality of heat injection design by providing temperature predictions based on planned heat injection rates. This novel automated workflow with data-driven models enhances reservoir management efficiency by reducing engineers’ unproductive time such as data manipulation and allowing them to focus on value-added works like analysis and optimization.
{"title":"Enhancing Reservoir Management Quality and Efficiency of Thermal Assets with Data-Driven Models","authors":"Tae Hyung Kim","doi":"10.2118/195265-MS","DOIUrl":"https://doi.org/10.2118/195265-MS","url":null,"abstract":"\u0000 Temperature monitoring is the most important surveillance in thermal assets, but temperature logging is limited in frequencies and locations. In addition, it is extremely difficult to review all the measured temperature and injection data manually since there are 10,000+ wells in Kern River field. To overcome the limitations, data-driven reservoir temperature models are presented that are built using past temperature logs and steam injection rates of the Kern River field, California.\u0000 Based on the physics and geologic understanding the reservoir, adequate input features were selected and queried. Data cleanup was conducted to remove erroneous data or fix data errors using statistical tools such as multivariate Gaussian distribution. Voronoi diagram based dynamic injector selection algorithm (DISA) was developed to correctly capture the injectors which impact on temperature changes of a temperature observation well. Based on geologic characteristics of the Kern River, reservoir was divided into two sub-reservoirs, North-East and South-West. Two full field models were developed for predicting maximum and mean temperatures of a heated zone with multi-layer perceptron for both sub-reservoirs using about 120,000 data points from over 25,000 temperature curves measured at 700+ temperature observation wells.\u0000 To estimate proper model update frequencies and verify the process, three yearly models (models 2015, 2016, and 2017) were built and validated by using one-year future temperature predictions in 2016, 2017, and 2018. For instance, model 2015 was trained with data until the end of 2015 and validated against 2016 data. Maximum temperature prediction r2 of 2017 South-West and North-East models were 0.96 and 0.98, respectively. Model 2017 has been deployed for alerting exception cases automatically and flagging abnormal temperature measurements. Also, the models improve the quality of heat injection design by providing temperature predictions based on planned heat injection rates. This novel automated workflow with data-driven models enhances reservoir management efficiency by reducing engineers’ unproductive time such as data manipulation and allowing them to focus on value-added works like analysis and optimization.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128443746","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}
Peila Chen, Anand Selveindran, Chandan Kumar, Yomdo Saloma, Sushanta Bose, S. Balasubramanian, G. Thakur
This work summarizes the prospect of EOR and sequestration using CO2 flooding from an Indian mature oil field in Assam through laboratory study, reservoir static modeling, dynamic simulation, pilot design, and techno-economic sensitivity studies. The geomodel was established by incorporating of contour maps, well positions and coordinates, well data and well logs, perforation depths and distribution of petrophysical properties as well as fluid properties. It was confirmed through PVT laboratory studies that CO2 injection can achieve the miscibility under reservoir conditions. The coreflooding test showed the significant incremental oil recovery by continuous CO2 injection and the residual oil saturation after miscible CO2 injection reached ~0.13PV. A fine scale geological model was built for entire reservoir and dynamic simulation work was performed on the geological model without upscaling. The history match of 51-year field production and pressure data in the whole reservoir was completed in a commercial simulator, and various development scenarios were investigated. Based on the results from CO2 EOR simulation study, we identified a pilot pattern area of ~ 60 acres with one injector and four producers. The CO2 was injected into reservoir at 150 metric ton per day for 5 years and cumulative injection volume is 15.4 BCF. Then the well is switched back to water injection afterward. Around 1 million STB incremental oil recovery was obtained in about 10 years, which corresponds to 11% of original oil in place in the flooded area. The CO2 utilization ratio is approximately 6 MCF/BBL. It is expected that CO2 flooding yields a pre-tax net cash flow of US dollars of 9.4 MM. CO2-EOR and storage in this mature field has a great techno-economic prospect. The investigation of CCUS opportunity and the substantial advancement in CO2 flood pilot design project have created an excitement in Indian Oil& Gas industry since the CCUS can significantly improve the domestic oil production from mature oilfields, and also reduce the carbon footprint in India. The volume of anthropogenic CO2 injection and storage in the reservoirs presents the great social and economic benefits for CCUS in India.
{"title":"CO2-EOR and Carbon Storage in Indian Oilfields: From Laboratory Study to Pilot Design","authors":"Peila Chen, Anand Selveindran, Chandan Kumar, Yomdo Saloma, Sushanta Bose, S. Balasubramanian, G. Thakur","doi":"10.2118/195378-MS","DOIUrl":"https://doi.org/10.2118/195378-MS","url":null,"abstract":"\u0000 This work summarizes the prospect of EOR and sequestration using CO2 flooding from an Indian mature oil field in Assam through laboratory study, reservoir static modeling, dynamic simulation, pilot design, and techno-economic sensitivity studies. The geomodel was established by incorporating of contour maps, well positions and coordinates, well data and well logs, perforation depths and distribution of petrophysical properties as well as fluid properties.\u0000 It was confirmed through PVT laboratory studies that CO2 injection can achieve the miscibility under reservoir conditions. The coreflooding test showed the significant incremental oil recovery by continuous CO2 injection and the residual oil saturation after miscible CO2 injection reached ~0.13PV.\u0000 A fine scale geological model was built for entire reservoir and dynamic simulation work was performed on the geological model without upscaling. The history match of 51-year field production and pressure data in the whole reservoir was completed in a commercial simulator, and various development scenarios were investigated. Based on the results from CO2 EOR simulation study, we identified a pilot pattern area of ~ 60 acres with one injector and four producers. The CO2 was injected into reservoir at 150 metric ton per day for 5 years and cumulative injection volume is 15.4 BCF. Then the well is switched back to water injection afterward. Around 1 million STB incremental oil recovery was obtained in about 10 years, which corresponds to 11% of original oil in place in the flooded area.\u0000 The CO2 utilization ratio is approximately 6 MCF/BBL. It is expected that CO2 flooding yields a pre-tax net cash flow of US dollars of 9.4 MM. CO2-EOR and storage in this mature field has a great techno-economic prospect.\u0000 The investigation of CCUS opportunity and the substantial advancement in CO2 flood pilot design project have created an excitement in Indian Oil& Gas industry since the CCUS can significantly improve the domestic oil production from mature oilfields, and also reduce the carbon footprint in India. The volume of anthropogenic CO2 injection and storage in the reservoirs presents the great social and economic benefits for CCUS in India.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129858912","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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