Spurr Naima, Lant Kimberly, S. Akshaya, Grey Billy
Water management in oil production is an increasingly burdensome issue for operators. As fields mature and begin to water out, effective treatments are needed to remain profitable. A new, more effective relative permeability modifier (RPM) is a remedy for water with positive effect on oil. The application is intended for sandstone reservoirs and can be used as a standalone treatment or in conjunction with an acid stimulation treatment. The application is a strong, long-term solution for water management at the near wellbore. Laboratory and field measurements are presented to show the effect of the RPM on sandstone for effect on water and oil. Laboratory analysis was conducted using core flow to measure regain permeability in low to high permeability Berea sandstone at temperatures of 150°F to 250°F (65.5°C 121°C). Field measurements include comparison of production of pre- and post-treatment of mature, high permeability sandstone formations with heavy oil reserves. Treatment zones were 25-30 feet with bottom hole static temperatures of 150-200°F and deployed with coiled tubing. Laboratory testing regain permeability showed that RPM treatment across the range of permeabilities could reduce water by more than 80% while regain permeability to oil is maintain a more than 90%. Field applications showed the initial treatment yielded a 700barrel (bbl) reduction in water while doubling oil production. As the wells stabilized, some of the initial momentum was slowed but showed stabilization of an increased oil production, lower water production and lowered BS&W.
{"title":"Got Water? An RPM Solution","authors":"Spurr Naima, Lant Kimberly, S. Akshaya, Grey Billy","doi":"10.2523/iptc-22334-ms","DOIUrl":"https://doi.org/10.2523/iptc-22334-ms","url":null,"abstract":"\u0000 Water management in oil production is an increasingly burdensome issue for operators. As fields mature and begin to water out, effective treatments are needed to remain profitable. A new, more effective relative permeability modifier (RPM) is a remedy for water with positive effect on oil.\u0000 The application is intended for sandstone reservoirs and can be used as a standalone treatment or in conjunction with an acid stimulation treatment. The application is a strong, long-term solution for water management at the near wellbore.\u0000 Laboratory and field measurements are presented to show the effect of the RPM on sandstone for effect on water and oil. Laboratory analysis was conducted using core flow to measure regain permeability in low to high permeability Berea sandstone at temperatures of 150°F to 250°F (65.5°C 121°C). Field measurements include comparison of production of pre- and post-treatment of mature, high permeability sandstone formations with heavy oil reserves. Treatment zones were 25-30 feet with bottom hole static temperatures of 150-200°F and deployed with coiled tubing.\u0000 Laboratory testing regain permeability showed that RPM treatment across the range of permeabilities could reduce water by more than 80% while regain permeability to oil is maintain a more than 90%.\u0000 Field applications showed the initial treatment yielded a 700barrel (bbl) reduction in water while doubling oil production. As the wells stabilized, some of the initial momentum was slowed but showed stabilization of an increased oil production, lower water production and lowered BS&W.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87554456","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}
Jagadeesh Unnam, Carola Rawson, Sammay Hernandez, Raqib Ali Shah
When operators feel comfortable with the performance and safety of a facility producing at its design conditions, it becomes natural for them to push the service company to produce even more. While it might appear safer to increase the capacity beyond the initial design of a crude-oil processing facility than a gas processing facility, many points must be checked using a debottleneck study to guarantee a safe and reliable operation. Schlumberger production facilities engineering, and operations teams collaborated on a debottleneck study to increase the capacity of a Middle East crude-oil processing facility by 40% of its design, which helped to achieve the annual production targets. Debottleneck studies require deep knowledge of the processing train and early identification of equipment presenting significant limitations, which, in a crude-oil processing facility, is the oil train equipment (i.e., heater treater and desalter). Validating these two pieces of equipment was the first step to overcoming challenges to increasing capacity. The original design of the heater treater used a forced-draft burner system, and the study showed severe limitations to safely releasing the necessary heat for the increased throughput. A change to the burner type and configuration was identified as a need; a natural-draft burner system was installed in addition to modifications to the fuel-gas train. This change enabled a greater heat release without compromising the mechanical integrity of the heater; however, because of limitations regarding the heat transfer surface area, total duty to the process fluid remained limited. To overcome this challenge, a mechanical device (turbulator) was designed to increase the convective heat transfer coefficient. The combined effect of these changes resulted in the delivery of the required heat duty to process fluids. For desalting, the challenge was in achieving the required salt specification. Key variables studied were the salinity of the wash water, mixing efficiencies, and the feasible extent of dehydration. Because of the high salinity of the wash water that was being used and limits to the mixing efficiency and ability to achieve deep dehydration, the recommendation was to change the wash-water source to fresh water. Detailed salt balance calculations demonstrated the incremental production increase from using fresh water. In addition, adequacy checks of other process equipment, storage tanks and their venting systems, pumps, pipework, valves, instruments, and utility systems were reviewed and confirmed to be suitable for the increased capacity with only minimal changes. The required modifications were implemented following the approved change management procedures and optimization of the process parameters of the entire processing facility by the operations team. This ensured a smooth and safe operation at a 40% greater flow rate than that provided by the design. Being the technology owner, integrator, and process
{"title":"The Art of Debottlenecking to Optimize Production in a Crude-Oil Processing Facility","authors":"Jagadeesh Unnam, Carola Rawson, Sammay Hernandez, Raqib Ali Shah","doi":"10.2523/iptc-22278-ms","DOIUrl":"https://doi.org/10.2523/iptc-22278-ms","url":null,"abstract":"\u0000 When operators feel comfortable with the performance and safety of a facility producing at its design conditions, it becomes natural for them to push the service company to produce even more. While it might appear safer to increase the capacity beyond the initial design of a crude-oil processing facility than a gas processing facility, many points must be checked using a debottleneck study to guarantee a safe and reliable operation.\u0000 Schlumberger production facilities engineering, and operations teams collaborated on a debottleneck study to increase the capacity of a Middle East crude-oil processing facility by 40% of its design, which helped to achieve the annual production targets.\u0000 Debottleneck studies require deep knowledge of the processing train and early identification of equipment presenting significant limitations, which, in a crude-oil processing facility, is the oil train equipment (i.e., heater treater and desalter). Validating these two pieces of equipment was the first step to overcoming challenges to increasing capacity.\u0000 The original design of the heater treater used a forced-draft burner system, and the study showed severe limitations to safely releasing the necessary heat for the increased throughput. A change to the burner type and configuration was identified as a need; a natural-draft burner system was installed in addition to modifications to the fuel-gas train. This change enabled a greater heat release without compromising the mechanical integrity of the heater; however, because of limitations regarding the heat transfer surface area, total duty to the process fluid remained limited. To overcome this challenge, a mechanical device (turbulator) was designed to increase the convective heat transfer coefficient. The combined effect of these changes resulted in the delivery of the required heat duty to process fluids.\u0000 For desalting, the challenge was in achieving the required salt specification. Key variables studied were the salinity of the wash water, mixing efficiencies, and the feasible extent of dehydration. Because of the high salinity of the wash water that was being used and limits to the mixing efficiency and ability to achieve deep dehydration, the recommendation was to change the wash-water source to fresh water. Detailed salt balance calculations demonstrated the incremental production increase from using fresh water. In addition, adequacy checks of other process equipment, storage tanks and their venting systems, pumps, pipework, valves, instruments, and utility systems were reviewed and confirmed to be suitable for the increased capacity with only minimal changes.\u0000 The required modifications were implemented following the approved change management procedures and optimization of the process parameters of the entire processing facility by the operations team. This ensured a smooth and safe operation at a 40% greater flow rate than that provided by the design.\u0000 Being the technology owner, integrator, and process","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83932694","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}
Mohammad S. Al-Kadem, Ryyan Bayounis, Ayman Khalaf, Abdullah Alghamdi
Downhole casing corrosion monitoring is a key element in production engineering as it ensures the integrity and safety of assets, maximizes the life and serviceability of a well, and contributes to a successful HSE management programs. Consequently, wells are frequently logged for corrosion and metal loss anomalies to monitor casing integrity. This study explores a method using geospatial analytical techniques to develop synthetic corrosion logs to optimize OPEX, supplement missing logs, and avoid production deferment and downtimes. The proposed method generates full synthetic corrosion logs using geospatial analysis based on available logs, then it maps metal loss defects across the entire field. The spatial mapping builds a 3D map based on depth using computational geometry and computer-aided engineering. Hundreds of thousands of data points from hundreds of logs, represented by (1) depth, (2) casing specifications, (3) cement properties, and (4) metal loss severity, have been fed into the framework to develop a variogram model using Kriging interpolation. By developing the variogram model, a map is generated at each depth point with casing metal loss ratio, and hence a full synthetic corrosion log is built. The data set of available corrosion logs was split into two parts; 70% for training the model and the remining 30 % for testing. Then a cross-verification check was done as well. The developed geospatial analytical model achieved an overall confidence level of 95% of all predicted logs generated using the geospatial analysis. Another scenario was initially studied that incorporates depth, metal loss percentages, and well age as the only input data points. However, this study yielded a lower accuracy level of only 90%. This percentage increased to 95% when incorporating formation characteristics, casing and cement properties into the model. The developed model enabled effective optimization of 1000 corrosion logs requirement through the generation of a full field metal loss severity map. The cost avoidance can be estimated to reach up to tens of millions of dollars due to the ability of predicting metal loss for critical wells without actual operation costs. On top of assuring well integrity, the developed method promotes health and safety of assets and personnel as it minimizes physical exposure of corrosive gases such as H2S.
{"title":"Synthetic Casing Corrosion Log Prediction Using Geospatial Analysis – A Digital Twin Concept","authors":"Mohammad S. Al-Kadem, Ryyan Bayounis, Ayman Khalaf, Abdullah Alghamdi","doi":"10.2523/iptc-22584-ms","DOIUrl":"https://doi.org/10.2523/iptc-22584-ms","url":null,"abstract":"\u0000 Downhole casing corrosion monitoring is a key element in production engineering as it ensures the integrity and safety of assets, maximizes the life and serviceability of a well, and contributes to a successful HSE management programs. Consequently, wells are frequently logged for corrosion and metal loss anomalies to monitor casing integrity. This study explores a method using geospatial analytical techniques to develop synthetic corrosion logs to optimize OPEX, supplement missing logs, and avoid production deferment and downtimes.\u0000 The proposed method generates full synthetic corrosion logs using geospatial analysis based on available logs, then it maps metal loss defects across the entire field. The spatial mapping builds a 3D map based on depth using computational geometry and computer-aided engineering. Hundreds of thousands of data points from hundreds of logs, represented by (1) depth, (2) casing specifications, (3) cement properties, and (4) metal loss severity, have been fed into the framework to develop a variogram model using Kriging interpolation. By developing the variogram model, a map is generated at each depth point with casing metal loss ratio, and hence a full synthetic corrosion log is built.\u0000 The data set of available corrosion logs was split into two parts; 70% for training the model and the remining 30 % for testing. Then a cross-verification check was done as well. The developed geospatial analytical model achieved an overall confidence level of 95% of all predicted logs generated using the geospatial analysis. Another scenario was initially studied that incorporates depth, metal loss percentages, and well age as the only input data points. However, this study yielded a lower accuracy level of only 90%. This percentage increased to 95% when incorporating formation characteristics, casing and cement properties into the model. The developed model enabled effective optimization of 1000 corrosion logs requirement through the generation of a full field metal loss severity map. The cost avoidance can be estimated to reach up to tens of millions of dollars due to the ability of predicting metal loss for critical wells without actual operation costs.\u0000 On top of assuring well integrity, the developed method promotes health and safety of assets and personnel as it minimizes physical exposure of corrosive gases such as H2S.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82691875","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}
Unconventional formations require advanced mechanical and index assessments to improve their understanding under different geomechanical processes. However, difficulties associated with obtaining cores from the target formations and the challenges with sample preparation increase the assessment complexity. This research compiles data from unconventional index properties and rock mechanical test results from published articles and reports. The parameters include rock mineralogy, rock mechanical properties (compressive strength and elastic properties), and petrophysical properties (porosity, TOC, and permeability). The study showcases the main differences between the global and regional (Middle East and North Africa) rock formations and presents the best analogs for the regional reservoirs. These findings supplement the scarce and complex procurement of the needed rock specimens and reduce the number of core samples required for detailed evaluations. These outcomes help reduce the costs (equipment, sample preparation, measurement time, and the number of specimens tested) associated with the unconventional rock experimental evaluation. In addition, this study explores the successful development strategy implemented in the unconventional reservoirs in China to accomplish commercial production and recommends appropriate rock analogs for detailed experimental evaluations. This paper is part of an in-depth literature data compilation of MENA regional and global unconventional formations. This section of the study focuses on the target unconventional formations of Saudi Arabia and the unconventional formations in China, the USA, and Canada.
{"title":"Not All Unconventional Reservoirs Are Similar: MENA Regional vs. Global Anisotropic Rock Index and Mechanical Characterization – Part 1","authors":"Eduardo Gramajo, R. Rached","doi":"10.2523/iptc-22186-ms","DOIUrl":"https://doi.org/10.2523/iptc-22186-ms","url":null,"abstract":"\u0000 Unconventional formations require advanced mechanical and index assessments to improve their understanding under different geomechanical processes. However, difficulties associated with obtaining cores from the target formations and the challenges with sample preparation increase the assessment complexity.\u0000 This research compiles data from unconventional index properties and rock mechanical test results from published articles and reports. The parameters include rock mineralogy, rock mechanical properties (compressive strength and elastic properties), and petrophysical properties (porosity, TOC, and permeability). The study showcases the main differences between the global and regional (Middle East and North Africa) rock formations and presents the best analogs for the regional reservoirs. These findings supplement the scarce and complex procurement of the needed rock specimens and reduce the number of core samples required for detailed evaluations. These outcomes help reduce the costs (equipment, sample preparation, measurement time, and the number of specimens tested) associated with the unconventional rock experimental evaluation. In addition, this study explores the successful development strategy implemented in the unconventional reservoirs in China to accomplish commercial production and recommends appropriate rock analogs for detailed experimental evaluations.\u0000 This paper is part of an in-depth literature data compilation of MENA regional and global unconventional formations. This section of the study focuses on the target unconventional formations of Saudi Arabia and the unconventional formations in China, the USA, and Canada.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82619628","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}
Miguel Gonzalez, Robert W. Adams, Tim Thiel, C. Gooneratne, A. Magana-Mora, Ali Safran, Faisal Ghamdi, C. Powell, Ed Hulse, J. Ramasamy, M. Deffenbaugh
Current mud monitoring practices are limited due to their reliance on manual measurements such as funnel viscometers, weight balances, or basic field rheometers. These manual practices impose restraints on the quantity and quality of the available data that are essential to ensure optimal and safe drilling operations. In this study, we introduce a new autonomous mud viscosity/density system based on an electromechanical tuning fork resonator. The system was integrated into an edge-computing system for improved data collection and deployment of machine learning models. The system was tested during a live drilling campaign. The viscosity/density sensor is based on an electromechanical tuning fork resonator. The sensor was integrated into a submergible housing for in-tank measurements. Two systems were developed for simultaneous measurements at inflow (possum belly) and outflow (suction pit). The data from the two systems were broadcast wirelessly to the central computer room at the rig for real-time display and data aggregation by the edge-computing system for the development of time-series analysis models using machine learning. During initial field testing, data from a single sensor were collected for various hours at a rate less than a sample per second. The test allowed for continuous monitoring of the mud consistency not accessible by current measurement practices. The data demonstrated the potential to perform real-time calculation and display of drilling parameters and to detect anomalies in the fluid that might be indicative of developing operational problems, which would enable the instrument to be used as an early-warning system and real-time calculation of drilling parameters. The system detailed here provides an essential building block to enable drilling automation. The robustness and compactness of the instrument allow it to be installed at various points in the mud circulation system for the generation of large data sets that can be processed using modern analytics algorithms in an edge-computing framework.
{"title":"Autonomous Viscosity/Density Sensing System for Drilling Edge-Computing System","authors":"Miguel Gonzalez, Robert W. Adams, Tim Thiel, C. Gooneratne, A. Magana-Mora, Ali Safran, Faisal Ghamdi, C. Powell, Ed Hulse, J. Ramasamy, M. Deffenbaugh","doi":"10.2523/iptc-21968-ms","DOIUrl":"https://doi.org/10.2523/iptc-21968-ms","url":null,"abstract":"\u0000 Current mud monitoring practices are limited due to their reliance on manual measurements such as funnel viscometers, weight balances, or basic field rheometers. These manual practices impose restraints on the quantity and quality of the available data that are essential to ensure optimal and safe drilling operations. In this study, we introduce a new autonomous mud viscosity/density system based on an electromechanical tuning fork resonator. The system was integrated into an edge-computing system for improved data collection and deployment of machine learning models. The system was tested during a live drilling campaign. The viscosity/density sensor is based on an electromechanical tuning fork resonator. The sensor was integrated into a submergible housing for in-tank measurements. Two systems were developed for simultaneous measurements at inflow (possum belly) and outflow (suction pit). The data from the two systems were broadcast wirelessly to the central computer room at the rig for real-time display and data aggregation by the edge-computing system for the development of time-series analysis models using machine learning. During initial field testing, data from a single sensor were collected for various hours at a rate less than a sample per second. The test allowed for continuous monitoring of the mud consistency not accessible by current measurement practices. The data demonstrated the potential to perform real-time calculation and display of drilling parameters and to detect anomalies in the fluid that might be indicative of developing operational problems, which would enable the instrument to be used as an early-warning system and real-time calculation of drilling parameters. The system detailed here provides an essential building block to enable drilling automation. The robustness and compactness of the instrument allow it to be installed at various points in the mud circulation system for the generation of large data sets that can be processed using modern analytics algorithms in an edge-computing framework.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88711100","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. Gryaznov, David J Wiprut, P. Basu, T. Jafarov, M. Reese, Johannes Vossen
The objectives of this study were to deliver a pre-drill and real-time (RT) geomechanical model and wellbore stability analysis for the planned horizontal well within license Block XIb, Republic of Georgia. The main target is fractured tight volcanoclastic Middle Eocene (ME) formation. Pre-drill and RT Wellbore stability analyses were performed enabling safe mud weight requirements and mud weight sensitivity to inclination for the planned wellbore, as this area is significantly understudied in terms of rock properties, pore pressure behaviour and geomechanics. The model study was based on the drilling experience of the offset well, drilled a mile away and containing many data sets: wireline logs and borehole images, FIT/LOT, pressure measurements, drilling experience and cuttings, well construction and from the current well containing basic LWD gamma ray and mud log. The main problem areas were defined based on the model. Pore pressure drove many of the observed challenges, including the Maikop overpressured shales forming significant breakout zones, and the overpressured Upper Eocene sand and reactive Navtlugi shales zone experiencing many tight hole events in the offset well. Pore Pressure was later updated for the current well based on the drilling exponent (Dxc) calibrated with mud gas data as a part of RT Geomechanics study. The natural fracture behaviour of ME was carefully studied to identify potentially critically stressed fractures and near-wellbore fracture slip. The models examined breakout during underbalanced drilling as well as optimal well azimuths to minimize potential fluid losses in open fractures during drilling and avoid water cut during production. The study found that the originally planned mud weight was too risky and has to be increased in the overburden formations to avoid massive breakouts, as experienced in the offset well. While crossing target ME fractured volcanoclastic slightly underbalanced drilling may be possible. The pre-drill fracture stability study successfully confirmed its reliability during operations and allowed confidently make RT decisions. As a result, concern for losses lowered while moving the azimuth from Shmin to SHmax direction and mud weight (MW) could be raised confidently up to required level. The conducted studies, despite many challenges and data uncertainties, significantly clarified potential drilling risks within the license block area, which was understudied in terms of geomechanics in past years. Additional value was provided to future drilling programs as well as highlighting data gaps and pathways for further geomechanical model improvement and uncertainty mitigation. The model is the first valuable step in developing regional geomechanical understanding. Increased MW helped to avoid major tight hole events, detailed natural fractures analysis helped to select wellbore azimuth optimal to avoid fluid losses. As a result, rate of penetration (ROP) increased 2.3 times compared to
{"title":"1D Geomechanical Modelling of a Complex Naturally Fractured Volcanoclastic Reservoir, Republic of Georgia","authors":"A. Gryaznov, David J Wiprut, P. Basu, T. Jafarov, M. Reese, Johannes Vossen","doi":"10.2523/iptc-22248-ms","DOIUrl":"https://doi.org/10.2523/iptc-22248-ms","url":null,"abstract":"\u0000 The objectives of this study were to deliver a pre-drill and real-time (RT) geomechanical model and wellbore stability analysis for the planned horizontal well within license Block XIb, Republic of Georgia. The main target is fractured tight volcanoclastic Middle Eocene (ME) formation. Pre-drill and RT Wellbore stability analyses were performed enabling safe mud weight requirements and mud weight sensitivity to inclination for the planned wellbore, as this area is significantly understudied in terms of rock properties, pore pressure behaviour and geomechanics.\u0000 The model study was based on the drilling experience of the offset well, drilled a mile away and containing many data sets: wireline logs and borehole images, FIT/LOT, pressure measurements, drilling experience and cuttings, well construction and from the current well containing basic LWD gamma ray and mud log.\u0000 The main problem areas were defined based on the model. Pore pressure drove many of the observed challenges, including the Maikop overpressured shales forming significant breakout zones, and the overpressured Upper Eocene sand and reactive Navtlugi shales zone experiencing many tight hole events in the offset well. Pore Pressure was later updated for the current well based on the drilling exponent (Dxc) calibrated with mud gas data as a part of RT Geomechanics study.\u0000 The natural fracture behaviour of ME was carefully studied to identify potentially critically stressed fractures and near-wellbore fracture slip. The models examined breakout during underbalanced drilling as well as optimal well azimuths to minimize potential fluid losses in open fractures during drilling and avoid water cut during production.\u0000 The study found that the originally planned mud weight was too risky and has to be increased in the overburden formations to avoid massive breakouts, as experienced in the offset well. While crossing target ME fractured volcanoclastic slightly underbalanced drilling may be possible. The pre-drill fracture stability study successfully confirmed its reliability during operations and allowed confidently make RT decisions. As a result, concern for losses lowered while moving the azimuth from Shmin to SHmax direction and mud weight (MW) could be raised confidently up to required level.\u0000 The conducted studies, despite many challenges and data uncertainties, significantly clarified potential drilling risks within the license block area, which was understudied in terms of geomechanics in past years. Additional value was provided to future drilling programs as well as highlighting data gaps and pathways for further geomechanical model improvement and uncertainty mitigation. The model is the first valuable step in developing regional geomechanical understanding.\u0000 Increased MW helped to avoid major tight hole events, detailed natural fractures analysis helped to select wellbore azimuth optimal to avoid fluid losses. As a result, rate of penetration (ROP) increased 2.3 times compared to ","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84796240","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}
W. Mahmud, Omran Elhamali Abdussalam, Yousef Swissi, S. Elmabrouk
Dump-flood is a powerful and convenient recovery technique that maintains a reservoir pressure where an aquifer and an oil leg are perforated in the same well. In gravity assisted dump-flood, GADF, water from a shallow waterbed above is injected by its own hydrostatic weight into an underneath oil bearing formation. In a power assisted dump-flood, PADF, the injection pressure from the waterbed maybe enhanced by utilizing electrical submersible pumps, ESP. In this work, both GADF and PADF were implemented in a mature depleted reservoir block for a quick pressure maintenance program. Three injectors were drilled and completed to have both the upper Gir and lower Gir intervals in communication. ESPs were installed in three wells to enhance the water gravity effect. Recovery Factor, RF, increased from 8.92% before the implementation of dump- flooding to 10.68% after the implementation with no signs of plugging or scaling in the reservoir. Reservoir pressure increased by 213 psi due to dump-flood implementation and oil production rate increased in one of the wells by 1629 barrel per day at an optimum choke size of 24/64 in. Dump-flooding is an excellent alternative to conventional water injection as the pilot injectors significantly stopped rapid pressure decline and improved production rates.
{"title":"Case Study of Gravity and Power Assisted Dump Floods Implemented in a Mature Oil Field","authors":"W. Mahmud, Omran Elhamali Abdussalam, Yousef Swissi, S. Elmabrouk","doi":"10.2523/iptc-22419-ms","DOIUrl":"https://doi.org/10.2523/iptc-22419-ms","url":null,"abstract":"\u0000 Dump-flood is a powerful and convenient recovery technique that maintains a reservoir pressure where an aquifer and an oil leg are perforated in the same well. In gravity assisted dump-flood, GADF, water from a shallow waterbed above is injected by its own hydrostatic weight into an underneath oil bearing formation. In a power assisted dump-flood, PADF, the injection pressure from the waterbed maybe enhanced by utilizing electrical submersible pumps, ESP. In this work, both GADF and PADF were implemented in a mature depleted reservoir block for a quick pressure maintenance program. Three injectors were drilled and completed to have both the upper Gir and lower Gir intervals in communication. ESPs were installed in three wells to enhance the water gravity effect. Recovery Factor, RF, increased from 8.92% before the implementation of dump- flooding to 10.68% after the implementation with no signs of plugging or scaling in the reservoir. Reservoir pressure increased by 213 psi due to dump-flood implementation and oil production rate increased in one of the wells by 1629 barrel per day at an optimum choke size of 24/64 in. Dump-flooding is an excellent alternative to conventional water injection as the pilot injectors significantly stopped rapid pressure decline and improved production rates.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90317840","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}
In an unconventional reservoir, rock matrix has a much larger storage capacity for hydrocarbon and significantly lower permeability than the natural and hydraulic fractures. It acts as a bottleneck for hydrocarbon flow from the reservoir to the production well during production and is a key parameter for controlling the well performance over a long period of time. A new laboratory technology is developed to accurately and efficiently measure the matrix permeability. We have developed the Aramco Nano Permeameter (ANP), a new laboratory technology for measuring the stress-dependent source rock permeability. While the conventional laboratory methods can only measure one permeability data point with one test run, ANP, based on the nonlinear solution to the gas flow equation, measures the rock matrix permeability for a non-fractured sample as a function of stress using a single test run and thus is very efficient. Permeability as a function of pore pressure at a given confining stress is measured with ANP for several Eagle Ford rock samples without fractures. The permeability curve shows complex behavior: permeability initially decreases with increasing pore pressure, as a result of Knudsen diffusion effect, and then increases with pore pressure owing to the mechanical deformation. The measured permeability curves are verified by comparing them with permeability values measured with other methods for selected pore pressures. The high measurement efficiency of ANP is also demonstrated. In summary, ANP is a laboratory method that is based on a theoretical idea that is significantly different from those currently used by the industry and thus provides a high measurement efficiency that the conventional methods cannot achieve.
{"title":"Aramco Nano Permeameter ANP: A New Laboratory Technology for Accurate and Efficient Measurements of Stress-Dependent Source Rock Permeability","authors":"Hui-Hai Liu, J. Zhang, M. Boudjatit","doi":"10.2523/iptc-22185-ea","DOIUrl":"https://doi.org/10.2523/iptc-22185-ea","url":null,"abstract":"\u0000 In an unconventional reservoir, rock matrix has a much larger storage capacity for hydrocarbon and significantly lower permeability than the natural and hydraulic fractures. It acts as a bottleneck for hydrocarbon flow from the reservoir to the production well during production and is a key parameter for controlling the well performance over a long period of time. A new laboratory technology is developed to accurately and efficiently measure the matrix permeability.\u0000 We have developed the Aramco Nano Permeameter (ANP), a new laboratory technology for measuring the stress-dependent source rock permeability. While the conventional laboratory methods can only measure one permeability data point with one test run, ANP, based on the nonlinear solution to the gas flow equation, measures the rock matrix permeability for a non-fractured sample as a function of stress using a single test run and thus is very efficient.\u0000 Permeability as a function of pore pressure at a given confining stress is measured with ANP for several Eagle Ford rock samples without fractures. The permeability curve shows complex behavior: permeability initially decreases with increasing pore pressure, as a result of Knudsen diffusion effect, and then increases with pore pressure owing to the mechanical deformation. The measured permeability curves are verified by comparing them with permeability values measured with other methods for selected pore pressures. The high measurement efficiency of ANP is also demonstrated.\u0000 In summary, ANP is a laboratory method that is based on a theoretical idea that is significantly different from those currently used by the industry and thus provides a high measurement efficiency that the conventional methods cannot achieve.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84900321","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}
Hussain A. Almajid, Alaa S. Shawly, Abdullah Al-Qasim
Asphaltene deposits are considered one of the most common issues facing oil fields with low particle stability that can result in loss of well potential, jeopardize wellbore accessibility and cause premature electrical submersible pump (ESP) failures. Traditionally, these deposits are treated with hydrocarbon based solvents, which have low flashpoints, making them hazardous and expensive. The objective of this paper is to provide a comprehensive solution to effectively remove asphaltene and sand fill accumulation that forms in the near wellbore region. This paper will also provide a computational analysis to accurately predict asphaltene precipitation during the production phase for optimized inhibition process. A laboratory approach was implemented to test the effectiveness of different water based solvent types, including aromatic, aliphatic and heteroatom instead of the commonly used hydrocarbon solvents such as xylene to dissolve asphaltene samples collected from the field and placed under anaerobic conditions. A thorough evaluation of fundamental asphaltene properties, including saturates, aromatics, resins and onset pressure, is incorporated into a computational model to understand and accurately predict asphaltene precipitation behavior. The newly developed system offers significant advantages compared to the traditional system in terms of treatment effectiveness, deployment cost and health, safety, and environment (HSE) due to its relatively high flashpoint. The new system utilizes a water based solvent that leaves the formation in a water wet state instead of oil wet, thus creating a barrier layer that will delay asphaltene accumulation and reduce treatment frequency. Field implementation and post-job results utilizing this newly developed water based aromatic solvent will be discussed, including treatment effectiveness to dissolve downhole asphaltene accumulations. Asphaltene inhibition programs have been implemented based on the results acquired from this model and frequent inspection conducted showed no asphaltene deposition over extended production periods. This paper provides a laboratory proven and field tested water based aromatic solvent that is effective in dissolving asphaltene accumulations resulting in improved well potential while reducing the frequency of required treatments thus maximizing productivity. This system is unique as it provides a high flashpoint water/solvent mixture with solvency power often greater than xylene with the additional benefit of leaving the formation strongly water-wet. The developed computational model helped to reduce the treatment frequency resulting in reduced expenses and sustained production.
{"title":"Developing an Integrated Solution to Remove and Inhibit Asphaltene Deposits Through a Laboratory and Field Proven Approach","authors":"Hussain A. Almajid, Alaa S. Shawly, Abdullah Al-Qasim","doi":"10.2523/iptc-22366-ms","DOIUrl":"https://doi.org/10.2523/iptc-22366-ms","url":null,"abstract":"\u0000 Asphaltene deposits are considered one of the most common issues facing oil fields with low particle stability that can result in loss of well potential, jeopardize wellbore accessibility and cause premature electrical submersible pump (ESP) failures. Traditionally, these deposits are treated with hydrocarbon based solvents, which have low flashpoints, making them hazardous and expensive. The objective of this paper is to provide a comprehensive solution to effectively remove asphaltene and sand fill accumulation that forms in the near wellbore region. This paper will also provide a computational analysis to accurately predict asphaltene precipitation during the production phase for optimized inhibition process.\u0000 A laboratory approach was implemented to test the effectiveness of different water based solvent types, including aromatic, aliphatic and heteroatom instead of the commonly used hydrocarbon solvents such as xylene to dissolve asphaltene samples collected from the field and placed under anaerobic conditions. A thorough evaluation of fundamental asphaltene properties, including saturates, aromatics, resins and onset pressure, is incorporated into a computational model to understand and accurately predict asphaltene precipitation behavior.\u0000 The newly developed system offers significant advantages compared to the traditional system in terms of treatment effectiveness, deployment cost and health, safety, and environment (HSE) due to its relatively high flashpoint. The new system utilizes a water based solvent that leaves the formation in a water wet state instead of oil wet, thus creating a barrier layer that will delay asphaltene accumulation and reduce treatment frequency. Field implementation and post-job results utilizing this newly developed water based aromatic solvent will be discussed, including treatment effectiveness to dissolve downhole asphaltene accumulations. Asphaltene inhibition programs have been implemented based on the results acquired from this model and frequent inspection conducted showed no asphaltene deposition over extended production periods.\u0000 This paper provides a laboratory proven and field tested water based aromatic solvent that is effective in dissolving asphaltene accumulations resulting in improved well potential while reducing the frequency of required treatments thus maximizing productivity. This system is unique as it provides a high flashpoint water/solvent mixture with solvency power often greater than xylene with the additional benefit of leaving the formation strongly water-wet. The developed computational model helped to reduce the treatment frequency resulting in reduced expenses and sustained production.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85521733","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}
Mohammad Farouk, Z. Al-jalal, Islam M. Hassan, Hope C. Marine, Saleem Al-Hameli, Ridha Al-Abdrabalnabi
Horizontal and deviated well architectures are now quite common as they facilitate drainage of reservoir in a cost-effective manner, such architectures introduce a challenging environment for subsequent completions and bottom hole operations performed through Coiled Tubing (CT) mainly due to friction between the coiled tubing string and well casing or reservoir formation rocks. To address this, a variety of techniques have been used over the years to reduce the friction between the metallic surfaces and extend the reach of the coiled tubing string to desired depths. Several Such techniques included-but were not limited to- using a specifically designed CT string (tapered CT strings, Pipe surface smoothing treatments), using mechanical aids (downhole coiled tubing tractors, coiled tubing agitators or vibrators) and increasing lubricity of the annulus fluid through the use of lubricants, there has also been many cases in which multiple techniques have been used at the same time to further extend the CT reach.4 The use of lubricants has always been the easiest technique as it does not require investment into equipment which would increase the complexity of the operation in addition to their cost. In this study, we are evaluating the friction reduction performance of an environmentally friendly surfactant-based metal friction reducer which will be called Lubricant A, the chemistry of Lubricant A has been used before in oilfield applications, but the authors believe this is the first time this chemistry is used for lubricity enhancement. We will be assessing Lubricant A performance at room temperature and 170°F to investigate its thermal stability and we will be evaluating its compatibility with common brines used during CT operations, especially at high concentrations of salt. We will also be comparing the performance of Lubricant A to that of a Co-polymer based Lubricant -which will be labeled Lubricanr B- in terms of Coefficient of Friction (CoF) reduction at room temperature and at 170°F. A core flood test has also been performed to investigate the impact of brines containing Lubricant A on reservoir rocks permeability. Based on our lab testing, Lubricant A manages to drop the coefficient of friction (CoF) by 60-70% in most cases and shows relatively high compatibility with different brines at different salt concentrations, outperforming Lubricant B in most cases. Lubricant A has also shown insignificant reduction in permeability during core flood tests, increasing the potential for its use in operations where formation damage might be a concern.
{"title":"Evaluation of Novel Surfactant Based Metal to Metal Friction Reducer","authors":"Mohammad Farouk, Z. Al-jalal, Islam M. Hassan, Hope C. Marine, Saleem Al-Hameli, Ridha Al-Abdrabalnabi","doi":"10.2523/iptc-22644-ms","DOIUrl":"https://doi.org/10.2523/iptc-22644-ms","url":null,"abstract":"\u0000 Horizontal and deviated well architectures are now quite common as they facilitate drainage of reservoir in a cost-effective manner, such architectures introduce a challenging environment for subsequent completions and bottom hole operations performed through Coiled Tubing (CT) mainly due to friction between the coiled tubing string and well casing or reservoir formation rocks.\u0000 To address this, a variety of techniques have been used over the years to reduce the friction between the metallic surfaces and extend the reach of the coiled tubing string to desired depths.\u0000 Several Such techniques included-but were not limited to- using a specifically designed CT string (tapered CT strings, Pipe surface smoothing treatments), using mechanical aids (downhole coiled tubing tractors, coiled tubing agitators or vibrators) and increasing lubricity of the annulus fluid through the use of lubricants, there has also been many cases in which multiple techniques have been used at the same time to further extend the CT reach.4\u0000 The use of lubricants has always been the easiest technique as it does not require investment into equipment which would increase the complexity of the operation in addition to their cost.\u0000 In this study, we are evaluating the friction reduction performance of an environmentally friendly surfactant-based metal friction reducer which will be called Lubricant A, the chemistry of Lubricant A has been used before in oilfield applications, but the authors believe this is the first time this chemistry is used for lubricity enhancement.\u0000 We will be assessing Lubricant A performance at room temperature and 170°F to investigate its thermal stability and we will be evaluating its compatibility with common brines used during CT operations, especially at high concentrations of salt.\u0000 We will also be comparing the performance of Lubricant A to that of a Co-polymer based Lubricant -which will be labeled Lubricanr B- in terms of Coefficient of Friction (CoF) reduction at room temperature and at 170°F.\u0000 A core flood test has also been performed to investigate the impact of brines containing Lubricant A on reservoir rocks permeability.\u0000 Based on our lab testing, Lubricant A manages to drop the coefficient of friction (CoF) by 60-70% in most cases and shows relatively high compatibility with different brines at different salt concentrations, outperforming Lubricant B in most cases.\u0000 Lubricant A has also shown insignificant reduction in permeability during core flood tests, increasing the potential for its use in operations where formation damage might be a concern.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81927020","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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