R. Bhagavatula, H. Al-Ajeel, Alaeldin Boushi, W. Eid, M. Elmofti, A. Allam, Abdullah Alhamad
Well ‘A’ is a horizontal well drilled in the primary and productive upper layer of the carbonate reservoir just below 7,750 ft TVD, with lateral length of 3,495 ft. This layer, due to inherent well placement, presented completion and production challenges attributed to low permeability and with limited scope for production enhancement. The asset team required an effective solution to drain reserves from this well and for evaluating future well placements. Near-wellbore (NWB) acid stimulation technique was preferred over conventional acid fracturing due to low vertical stress contrast and high tortuosity effects caused by lateral azimuth relative to maximum stress orientation. Based on the Bernoulli concept for fluid diversion and using a dual path pumping system, initiation and propagation of micro-fractures was achieved by pumping fluid through tubing and annulus with a controlled pump schedule. A specially designed high-pressure tool was used for creating formation cavity by pumping acid through tubing. Increasing pressure on the bottom of cavity initiates micro-fracture causing annular fluid to be pulled into the fracture and subsequently extending it. The NWB stimulation was designed and carried out in 50 stages along the lateral. This was followed by 29-stage matrix acid stimulation using 20% HCl and with pulsonix tool for acid placement. Initial well productivity (PI) was estimated at 0.16 STB/D/psi. Post stimulation treatment resulted in a nine-fold PI improvement. Production post stimulation was 720 barrels oil per day (bopd) with 7% water cut (w.c). The NWB stimulation enabled significant productivity increment with accelerated production. It is customizable enabling design and placement of multiple micro-fractures. Additional hardware for wellbore isolation during treatment is not required. It is economical in comparison to conventional fracturing treatment and could be extended for cased or liner completions in vertical or deviated wells.
{"title":"Enhanced Near Wellbore Acid Stimulation in Horizontal Open Hole Well Increased Influx from Tight Carbonate Formation in North Kuwait - Case Study.","authors":"R. Bhagavatula, H. Al-Ajeel, Alaeldin Boushi, W. Eid, M. Elmofti, A. Allam, Abdullah Alhamad","doi":"10.2118/191893-MS","DOIUrl":"https://doi.org/10.2118/191893-MS","url":null,"abstract":"\u0000 Well ‘A’ is a horizontal well drilled in the primary and productive upper layer of the carbonate reservoir just below 7,750 ft TVD, with lateral length of 3,495 ft. This layer, due to inherent well placement, presented completion and production challenges attributed to low permeability and with limited scope for production enhancement. The asset team required an effective solution to drain reserves from this well and for evaluating future well placements.\u0000 Near-wellbore (NWB) acid stimulation technique was preferred over conventional acid fracturing due to low vertical stress contrast and high tortuosity effects caused by lateral azimuth relative to maximum stress orientation. Based on the Bernoulli concept for fluid diversion and using a dual path pumping system, initiation and propagation of micro-fractures was achieved by pumping fluid through tubing and annulus with a controlled pump schedule. A specially designed high-pressure tool was used for creating formation cavity by pumping acid through tubing. Increasing pressure on the bottom of cavity initiates micro-fracture causing annular fluid to be pulled into the fracture and subsequently extending it.\u0000 The NWB stimulation was designed and carried out in 50 stages along the lateral. This was followed by 29-stage matrix acid stimulation using 20% HCl and with pulsonix tool for acid placement. Initial well productivity (PI) was estimated at 0.16 STB/D/psi. Post stimulation treatment resulted in a nine-fold PI improvement. Production post stimulation was 720 barrels oil per day (bopd) with 7% water cut (w.c).\u0000 The NWB stimulation enabled significant productivity increment with accelerated production. It is customizable enabling design and placement of multiple micro-fractures. Additional hardware for wellbore isolation during treatment is not required. It is economical in comparison to conventional fracturing treatment and could be extended for cased or liner completions in vertical or deviated wells.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83994824","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}
Y. Santin, K. Matar, E. Montes, S. Gorgi, J. Joya, M. Bu-mijdad, H. Al-Mubarak, M. Al-Lafi, A. Al-Hamad, H. Al-Askar, M. Al-Shamaa, O. Al-Enizi, A. Bu-Qurais, S. Madhavan, M. Al-Dashti
Injection profile enhancement has been one of the primary objectives for an operator in Kuwait. Stimulation interventions in injector wells directly affect the enhancement of oil recovery in producer wells. This paper presents the application of a verifiable stimulation intervention in a water injector well to help achieve the operator's objectives. The intervention presented several challenges. There was limited information available for the newly drilled carbonate formation under consideration in the Greater Burgan Field. Additionally, the fiberglass well tubing required significant attention before running in hole (RIH) with coiled tubing (CT). A high concentration of H2S was identified in Formation A; therefore, gas returns were also a potential issue. This paper discusses the methods used to help address these challenges. During this case study, real-time fiber-optic cable CT (RTFOCT) technology was applied in the fiberglass tubing injector well to determine initial well injection profile and adjust treatment accordingly. This technology includes a fiber-optic cable integrated into the CT pipe and a modular sensing bottomhole assembly (BHA). RTFOCT technology allows for rigless operations and performs interval diagnostics, stimulation treatment, and evaluation in a single CT run. During this case study, the well injectivity increased by more than 100%. Diagnostics and evaluation were performed by analyzing the well thermal profile using fiber-optic distributed temperature sensing (DTS). The BHA helped ensure accurate fluid placement during the treatment using real-time pressure, temperature, and depth-correlation sensors. The RTFOCT technology provided real-time downhole information that was used to analyze reservoir parameters, help ensure accurate fluid placement, and enable quick and smart decisions regarding the stimulation treatment stages based on the fluid intake in different zones. During injection, the heterogeneous fluid flow became homogeneous along the interval confirmed with the thermal-hydraulic model (THM). This helped reliably complete the intervention operations and delay possible water breakthrough in the producer wells and extended reservoir recovery.
{"title":"Reliable Carbonate Stimulation Using Distributed Temperature Sensing Diagnostics and Real-Time Fiber-Optic Coiled Tubing Intervention in Kuwait","authors":"Y. Santin, K. Matar, E. Montes, S. Gorgi, J. Joya, M. Bu-mijdad, H. Al-Mubarak, M. Al-Lafi, A. Al-Hamad, H. Al-Askar, M. Al-Shamaa, O. Al-Enizi, A. Bu-Qurais, S. Madhavan, M. Al-Dashti","doi":"10.2118/191914-MS","DOIUrl":"https://doi.org/10.2118/191914-MS","url":null,"abstract":"\u0000 Injection profile enhancement has been one of the primary objectives for an operator in Kuwait. Stimulation interventions in injector wells directly affect the enhancement of oil recovery in producer wells. This paper presents the application of a verifiable stimulation intervention in a water injector well to help achieve the operator's objectives.\u0000 The intervention presented several challenges. There was limited information available for the newly drilled carbonate formation under consideration in the Greater Burgan Field. Additionally, the fiberglass well tubing required significant attention before running in hole (RIH) with coiled tubing (CT). A high concentration of H2S was identified in Formation A; therefore, gas returns were also a potential issue. This paper discusses the methods used to help address these challenges. During this case study, real-time fiber-optic cable CT (RTFOCT) technology was applied in the fiberglass tubing injector well to determine initial well injection profile and adjust treatment accordingly. This technology includes a fiber-optic cable integrated into the CT pipe and a modular sensing bottomhole assembly (BHA).\u0000 RTFOCT technology allows for rigless operations and performs interval diagnostics, stimulation treatment, and evaluation in a single CT run. During this case study, the well injectivity increased by more than 100%. Diagnostics and evaluation were performed by analyzing the well thermal profile using fiber-optic distributed temperature sensing (DTS). The BHA helped ensure accurate fluid placement during the treatment using real-time pressure, temperature, and depth-correlation sensors. The RTFOCT technology provided real-time downhole information that was used to analyze reservoir parameters, help ensure accurate fluid placement, and enable quick and smart decisions regarding the stimulation treatment stages based on the fluid intake in different zones. During injection, the heterogeneous fluid flow became homogeneous along the interval confirmed with the thermal-hydraulic model (THM). This helped reliably complete the intervention operations and delay possible water breakthrough in the producer wells and extended reservoir recovery.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85261367","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper discusses the successful design, testing, and application of a new filter-cake breaker technology based on lactic acid chemistry. This technology provided prolonged delay in filter-cake breakthrough time at 220°F, which ensured coverage of the entire open hole, improved uniform filter-cake removal, minimized brine losses, and exceeded the expected production rates in different layers of the offshore Abu Dhabi reservoir. Reservoir characterization was a fundamental component in the identification of the proper solution to maximize the return on investment of the assets. Temperature, permeability, porosity, and the nature of the reservoirs were studied thoroughly to determine one solution to be used in different reservoirs. Drilling fluid characterization (non-damaging with proper bridging package) and a proper filter-cake design were crucial to exceed the targeted production of the reservoirs. The paper discusses all steps from the laboratory testing of the breaker, application in different layers of the reservoir, and results obtained from the applications. Lactic acid precursor was confirmed to be the "one fit solution" to cover the different reservoir layers. Because of its chemical structure, the hydrolysis process is slower than other breaker types currently available, which made it possible to maximize the breakthrough time at elevated temperatures, minimize completion fluid losses, and optimize the completion operations. Equally important, as an acid precursor rather than a live acid, this solution enabled the rig site personnel to implement the solution without affecting the health, safety, and environment (HSE) aspects that are fundamental in offshore locations. The possibility of pumping this solution through the rig pits enabled the jobs to be performed without additional equipment generally required for well stimulation. The achievement of these goals, supported by the higher production observed during the flow-back of the well, demonstrated how this solution maximized the return on investment for the assets located offshore Abu Dhabi. The innovative use of lactic acid chemistry in the breaker, as compared to the conventional formic acid precursor breakers that are widely available, provided superior delay at higher bottomhole temperatures (in this case, 220°F) because of the slower acid liberation rate.
{"title":"New Filter-Cake Breaker Technology Maximizes Production Rates by Removing Near-Wellbore Damage Zone with Delay Mechanism Designed for High Temperature Reservoirs: Offshore Abu Dhabi","authors":"M. Nasrallah, M. Vinci","doi":"10.2118/191888-MS","DOIUrl":"https://doi.org/10.2118/191888-MS","url":null,"abstract":"\u0000 This paper discusses the successful design, testing, and application of a new filter-cake breaker technology based on lactic acid chemistry. This technology provided prolonged delay in filter-cake breakthrough time at 220°F, which ensured coverage of the entire open hole, improved uniform filter-cake removal, minimized brine losses, and exceeded the expected production rates in different layers of the offshore Abu Dhabi reservoir.\u0000 Reservoir characterization was a fundamental component in the identification of the proper solution to maximize the return on investment of the assets. Temperature, permeability, porosity, and the nature of the reservoirs were studied thoroughly to determine one solution to be used in different reservoirs. Drilling fluid characterization (non-damaging with proper bridging package) and a proper filter-cake design were crucial to exceed the targeted production of the reservoirs. The paper discusses all steps from the laboratory testing of the breaker, application in different layers of the reservoir, and results obtained from the applications.\u0000 Lactic acid precursor was confirmed to be the \"one fit solution\" to cover the different reservoir layers. Because of its chemical structure, the hydrolysis process is slower than other breaker types currently available, which made it possible to maximize the breakthrough time at elevated temperatures, minimize completion fluid losses, and optimize the completion operations. Equally important, as an acid precursor rather than a live acid, this solution enabled the rig site personnel to implement the solution without affecting the health, safety, and environment (HSE) aspects that are fundamental in offshore locations. The possibility of pumping this solution through the rig pits enabled the jobs to be performed without additional equipment generally required for well stimulation. The achievement of these goals, supported by the higher production observed during the flow-back of the well, demonstrated how this solution maximized the return on investment for the assets located offshore Abu Dhabi.\u0000 The innovative use of lactic acid chemistry in the breaker, as compared to the conventional formic acid precursor breakers that are widely available, provided superior delay at higher bottomhole temperatures (in this case, 220°F) because of the slower acid liberation rate.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89489953","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}
Conventional artificial lift systems are limited in their application by depth, borehole trajectory and chemistry of the produced media. This paper presents a concentric tubular pumping system, combined with an efficient hydraulic pump to overcome the limitations of existing artificial lift systems and to assure a cost-effective production. This pumping system consists of a specially designed plunger assembly and barrel combination, which is driven by a hydraulic pressure unit from the surface without any mechanical connection. The hydraulic pump itself can be circulated into and out of the borehole or can be run by slickline, resulting in fast and low-cost operations. The pump is designed to be run as a concentric tubular pumping system with several advantages, especially in enhanced oil recovery and unloading of gas well operations. This new pump type is designed and manufactured in cooperation with the industry and tested at the Montanuniversität Leoben, Austria. The performance tests have demonstrated the saving potential regarding energy efficiency as well as a reduction in CAPEX and OPEX. The unique design of this pump owns a very low number of moving parts, such no mechanical connection to the surface, and such providing minimal exposure to wear and corrosion. Tests have shown that the pump is very adaptable regarding production rate, which requires just a change in surface hydraulic pressure. Based on experience the concentric tubular pumping system is the best selection for unloading of gas wells to enhance the lifetime of the completions. As a result, of the natural phase separation of liquids and gases, the presented pumping system has shown to be the ideal choice for the usage in all types of wells. This completely new pump type exceeds the performance of existing artificial lift systems for unloading of gas wells, increases the mean time between failures and reduces the lifting costs essentially. These major issues are most important in times of low gas price.
{"title":"Hydraulic Concentric Tubular Pumping System for Unloading Gas Wells","authors":"Langbauer Clemens, P. Vita, J. Gerald, H. Herbert","doi":"10.2118/192091-MS","DOIUrl":"https://doi.org/10.2118/192091-MS","url":null,"abstract":"\u0000 Conventional artificial lift systems are limited in their application by depth, borehole trajectory and chemistry of the produced media. This paper presents a concentric tubular pumping system, combined with an efficient hydraulic pump to overcome the limitations of existing artificial lift systems and to assure a cost-effective production.\u0000 This pumping system consists of a specially designed plunger assembly and barrel combination, which is driven by a hydraulic pressure unit from the surface without any mechanical connection. The hydraulic pump itself can be circulated into and out of the borehole or can be run by slickline, resulting in fast and low-cost operations. The pump is designed to be run as a concentric tubular pumping system with several advantages, especially in enhanced oil recovery and unloading of gas well operations. This new pump type is designed and manufactured in cooperation with the industry and tested at the Montanuniversität Leoben, Austria.\u0000 The performance tests have demonstrated the saving potential regarding energy efficiency as well as a reduction in CAPEX and OPEX. The unique design of this pump owns a very low number of moving parts, such no mechanical connection to the surface, and such providing minimal exposure to wear and corrosion. Tests have shown that the pump is very adaptable regarding production rate, which requires just a change in surface hydraulic pressure. Based on experience the concentric tubular pumping system is the best selection for unloading of gas wells to enhance the lifetime of the completions. As a result, of the natural phase separation of liquids and gases, the presented pumping system has shown to be the ideal choice for the usage in all types of wells.\u0000 This completely new pump type exceeds the performance of existing artificial lift systems for unloading of gas wells, increases the mean time between failures and reduces the lifting costs essentially. These major issues are most important in times of low gas price.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91544444","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}
Yuemin Gu, D. Gao, Yang Jin, Wang Zhiyue, Xin Li, Leichuan Tan
Shale gas in the mountain area is exploited in well factory mode. Learning effect due to well factory mode significantly affect the drilling cost, which has a powerful effect on platform location. The learning index, which is quantitative assessment of learning effect in the process of shale gas exploitment, is made by adjusted cosine similarity in this paper. The learning index, of which data comes from adjacent well, takes drilling cost, the well length and drilling time into account. The platform location optimization model, which considers learning effect, maximum number of wells one platform allowed and well trajectory, is established. The genetic algorithm is applied to solve the optimization model and the genetic operator is improved base on shale gas exploitation in mountain area. All the calculation procedure of genetic algorithm is performed in this work. The case study indicates that the optimization model can reduce the platform amount in a given area and increase the well amount one platform drills, namely, reduce the drilling cost by optimizing the platform location. The study demonstrates that the platform location optimization model established in this paper can both effectively quantify learning effect due to the well factory mode drilling in mountain area and decrease the drilling cost.
{"title":"A Model for Platform Location Optimization in Shale Gas with Learning Effect","authors":"Yuemin Gu, D. Gao, Yang Jin, Wang Zhiyue, Xin Li, Leichuan Tan","doi":"10.2118/192124-MS","DOIUrl":"https://doi.org/10.2118/192124-MS","url":null,"abstract":"\u0000 Shale gas in the mountain area is exploited in well factory mode. Learning effect due to well factory mode significantly affect the drilling cost, which has a powerful effect on platform location. The learning index, which is quantitative assessment of learning effect in the process of shale gas exploitment, is made by adjusted cosine similarity in this paper. The learning index, of which data comes from adjacent well, takes drilling cost, the well length and drilling time into account. The platform location optimization model, which considers learning effect, maximum number of wells one platform allowed and well trajectory, is established. The genetic algorithm is applied to solve the optimization model and the genetic operator is improved base on shale gas exploitation in mountain area. All the calculation procedure of genetic algorithm is performed in this work. The case study indicates that the optimization model can reduce the platform amount in a given area and increase the well amount one platform drills, namely, reduce the drilling cost by optimizing the platform location. The study demonstrates that the platform location optimization model established in this paper can both effectively quantify learning effect due to the well factory mode drilling in mountain area and decrease the drilling cost.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73128522","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}
Accurate flowrate measurements in petroleum production systems are important for optimization, fiscal metering, and production allocation. Sometimes, Virtual Flow Meters (VFMs) are used for this purpose instead of physical meters to reduce cost. These systems estimate the flowrates using a computational model that represents accurately the production system of interest. Since VFM systems mostly rely on pressure and temperature measurements, it is important to understand how accuracy and degradation of sensors influence the VFM flowrate estimates. In this work, a VFM system for a subsea oil well was created using a transient multiphase model built in a commercial software and controlled from an external computational routine. A statistical analysis of VFM simulation results was performed to quantify the effect of pressure sensors degradation on the VFM flowrate estimates. In addition, the effect of temperature matching and a segmented approach to represent the well heat transfer were evaluated. The analysis showed that the sensor degradation effect should be considered in VFM systems carefully, especially if a high estimation accuracy is required. Measurement drift was found to be the most critical factor of the sensor degradation but high measurement noise can also cause considerable errors of the flowrate estimates. In addition, it was found that a complex representation of the wellbore heat transfer is not required to obtain accurate flowrate predictions and simplified models can be used instead.
{"title":"Statistical Analysis of Effect of Sensor Degradation and Heat Transfer Modeling on Multiphase Flowrate Estimates from a Virtual Flow Meter","authors":"Timur Bikmukhametov, M. Stanko, J. Jäschke","doi":"10.2118/191962-MS","DOIUrl":"https://doi.org/10.2118/191962-MS","url":null,"abstract":"\u0000 Accurate flowrate measurements in petroleum production systems are important for optimization, fiscal metering, and production allocation. Sometimes, Virtual Flow Meters (VFMs) are used for this purpose instead of physical meters to reduce cost. These systems estimate the flowrates using a computational model that represents accurately the production system of interest. Since VFM systems mostly rely on pressure and temperature measurements, it is important to understand how accuracy and degradation of sensors influence the VFM flowrate estimates.\u0000 In this work, a VFM system for a subsea oil well was created using a transient multiphase model built in a commercial software and controlled from an external computational routine. A statistical analysis of VFM simulation results was performed to quantify the effect of pressure sensors degradation on the VFM flowrate estimates. In addition, the effect of temperature matching and a segmented approach to represent the well heat transfer were evaluated.\u0000 The analysis showed that the sensor degradation effect should be considered in VFM systems carefully, especially if a high estimation accuracy is required. Measurement drift was found to be the most critical factor of the sensor degradation but high measurement noise can also cause considerable errors of the flowrate estimates. In addition, it was found that a complex representation of the wellbore heat transfer is not required to obtain accurate flowrate predictions and simplified models can be used instead.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"132 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74692915","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}
Qinghai Yang, Ming Li, Quanbin Wang, Meng Siwei, Ming Eryang
The conductance sensor based water cut meter is usually used to measure content of the oil-water two phase mixed fluid for periodical well production logging. In order to solve the real-time monitoring problem of downhole water cut, this paper proposes an online water cut measurement system based on the conductance sensor technology. Through the newly developed system, the continuous and permanent water cut measuring can be realized. The system consists of two conductance sensors, one temperature sensor, sampling mechanism and control & storage unit. Due to different density of oil and water, the two conductors with cylindrical poles, equipped on the upside and downside of the fluid inlet respectively, sense the conductivity of the oil-water mixed fluid and the detached water. With the real-time sampled downhole temperature, the conductivity values are compensated to reflect the real characters of the two kinds of liquid. According to Maxwell's model of oil-water mixed fluid and the correction parameters from offline calibration, the water cut is deduced. Since all units are designed with low-power consumption and high protection level, the system can operate permanently and provide online monitoring values. The water cut measurement system is tested in a physical testing environment with different conditions of the oil-water mixing ratio, the mineralization degree of water, the liquid temperature and the flow rate. Testing results show that the water cut in oil-water mixed fluid and the sampled conductivity follow the Maxwell's model approximately, where the error between testing data and theoretical value is within 3% especially for the high water cut cases. When the temperature changes, the measured water cut value basically does not variate, although sampled conductivity of the two sensors change a lot with temperature. Different mineralization degree of water would affect the measured water cut result slightly, which should be due to the conflicts between the large conductance range and the sampling accuracy. The flow rate is another element to make the measured result fluctuation, but the water cut would be stable when using the average value within a period. In brief, the system provides real-time water cut measurement and the measuring accuracy can satisfy the requirements of petroleum production. The conductance sensor based water cut measurement system realizes real-time measuring of oil-water mixing ratio for oil production and can provide online parameters for optimizing production process rapidly. All electronic units are designed with low-power consumption, which ensure the system to run downhole permanently.
{"title":"An Online Water Cut Measurement System Based on the Conductance Sensor","authors":"Qinghai Yang, Ming Li, Quanbin Wang, Meng Siwei, Ming Eryang","doi":"10.2118/192049-MS","DOIUrl":"https://doi.org/10.2118/192049-MS","url":null,"abstract":"\u0000 The conductance sensor based water cut meter is usually used to measure content of the oil-water two phase mixed fluid for periodical well production logging. In order to solve the real-time monitoring problem of downhole water cut, this paper proposes an online water cut measurement system based on the conductance sensor technology. Through the newly developed system, the continuous and permanent water cut measuring can be realized. The system consists of two conductance sensors, one temperature sensor, sampling mechanism and control & storage unit. Due to different density of oil and water, the two conductors with cylindrical poles, equipped on the upside and downside of the fluid inlet respectively, sense the conductivity of the oil-water mixed fluid and the detached water. With the real-time sampled downhole temperature, the conductivity values are compensated to reflect the real characters of the two kinds of liquid. According to Maxwell's model of oil-water mixed fluid and the correction parameters from offline calibration, the water cut is deduced. Since all units are designed with low-power consumption and high protection level, the system can operate permanently and provide online monitoring values. The water cut measurement system is tested in a physical testing environment with different conditions of the oil-water mixing ratio, the mineralization degree of water, the liquid temperature and the flow rate. Testing results show that the water cut in oil-water mixed fluid and the sampled conductivity follow the Maxwell's model approximately, where the error between testing data and theoretical value is within 3% especially for the high water cut cases. When the temperature changes, the measured water cut value basically does not variate, although sampled conductivity of the two sensors change a lot with temperature. Different mineralization degree of water would affect the measured water cut result slightly, which should be due to the conflicts between the large conductance range and the sampling accuracy. The flow rate is another element to make the measured result fluctuation, but the water cut would be stable when using the average value within a period. In brief, the system provides real-time water cut measurement and the measuring accuracy can satisfy the requirements of petroleum production. The conductance sensor based water cut measurement system realizes real-time measuring of oil-water mixing ratio for oil production and can provide online parameters for optimizing production process rapidly. All electronic units are designed with low-power consumption, which ensure the system to run downhole permanently.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80171884","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}
Laurie S. Duthie, Hussain Saiood, H. Al-Marri, D. Ahmed
Challenges are usually exaggerated related to matrix acid stimulation and fluid placement in extended reach horizontal wells and demand a constant flow of innovation. The optimization of real time fluid placement, increasing the reservoir contact and establishing uniform fluid distribution for better production/ injection across the openhole interval is one area that can benefit from these new innovations. Coiled tubing (CT) equipped with a tractor and new real-time downhole flow measurement capabilities was selected as the solution. While a CT tractor facilitates the reach, flow measurements provide a clearer understanding of downhole injectivity patterns. Real-time fluid direction and velocity are acquired and used to identify high/low intake zones. The data is subsequently applied to adjust the stimulation diversion schedule accordingly. In a water injection well, baseline data was acquired before commencing a matrix stimulation treatment. The treatment was squeezed through the CT at the depths highlighted as low intake during the initial profiling. The coiled tubing real-time flow tool was deployed during the matrix stimulation treatment of the extended reach water injection well with a downhole tractor. The flow tool measured the baseline injection profile which was then correlated with the mobility data. Results from the pre-stimulation profile showed that 70% of injection was entering in a 3,000 ft. section near the toe (24,500 ft.), whereas 30% of injection was spread across the remainder of the open-hole interval. The acquired flow data was able to identify sections of the wellbore featuring low mobility and viscous fluids, which in turn provided additional information for the adjustment of the subsequent stimulation pumping sequence. The real-time optimization of stimulation treatment helped to increase the post-stimulation injection rate by over 4 times the pre-stimulation rate. The combination of CT tractor with real-time flow measurement tool provides an efficient means to stimulate extended-reach water injector wells. The basic technology behind the real time flow tool is a synchronized system with a series of heating elements and temperature sensors along the tool to determine the direction and mean velocity of the fluid. This ultimately allows for a more accurate placement of stimulation treatment to the targeted zones. The technology can also be applied for extended reach oil producers, however, for optimum tool performance, the well should first be displaced with an inert fluid.
{"title":"Introduction of Real-Time Flow Measurements Opens New Paths to Overcome Challenges Encountered During the Acid Stimulation of Extended Reach Wells","authors":"Laurie S. Duthie, Hussain Saiood, H. Al-Marri, D. Ahmed","doi":"10.2118/191981-MS","DOIUrl":"https://doi.org/10.2118/191981-MS","url":null,"abstract":"\u0000 Challenges are usually exaggerated related to matrix acid stimulation and fluid placement in extended reach horizontal wells and demand a constant flow of innovation. The optimization of real time fluid placement, increasing the reservoir contact and establishing uniform fluid distribution for better production/ injection across the openhole interval is one area that can benefit from these new innovations.\u0000 Coiled tubing (CT) equipped with a tractor and new real-time downhole flow measurement capabilities was selected as the solution. While a CT tractor facilitates the reach, flow measurements provide a clearer understanding of downhole injectivity patterns. Real-time fluid direction and velocity are acquired and used to identify high/low intake zones. The data is subsequently applied to adjust the stimulation diversion schedule accordingly. In a water injection well, baseline data was acquired before commencing a matrix stimulation treatment. The treatment was squeezed through the CT at the depths highlighted as low intake during the initial profiling.\u0000 The coiled tubing real-time flow tool was deployed during the matrix stimulation treatment of the extended reach water injection well with a downhole tractor. The flow tool measured the baseline injection profile which was then correlated with the mobility data. Results from the pre-stimulation profile showed that 70% of injection was entering in a 3,000 ft. section near the toe (24,500 ft.), whereas 30% of injection was spread across the remainder of the open-hole interval. The acquired flow data was able to identify sections of the wellbore featuring low mobility and viscous fluids, which in turn provided additional information for the adjustment of the subsequent stimulation pumping sequence. The real-time optimization of stimulation treatment helped to increase the post-stimulation injection rate by over 4 times the pre-stimulation rate.\u0000 The combination of CT tractor with real-time flow measurement tool provides an efficient means to stimulate extended-reach water injector wells. The basic technology behind the real time flow tool is a synchronized system with a series of heating elements and temperature sensors along the tool to determine the direction and mean velocity of the fluid. This ultimately allows for a more accurate placement of stimulation treatment to the targeted zones. The technology can also be applied for extended reach oil producers, however, for optimum tool performance, the well should first be displaced with an inert fluid.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86109393","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}
Vanessa Vera, Carlos A. Torres, E. Delgado, Carlos Pacheco, J. Higuera, Monica Torres
To measure and analyze reservoir pressure, conductivity, gas/oil ratio (GOR), and skin value, it is necessary to run a pressure buildup (PBU) test to the corresponding zone of interest in the well. This paper describes how the implementation of a coiled tubing (CT) real-time fiber-optic (RTFO) integrated system and a retrievable packer were determining factors to successfully develop both PBU in an upper formation and a pressure evaluation in the lower formation in the same run. To help ensure isolation and evaluation of each high potential zone in the well, conventional methods involve multiple procedures requiring multiple runs. Using the CT RTFO (Vera et al. 2018) integrated system with a retrievable packer, only one run was necessary to complete the PBU program, which involves the isolation and corresponding log of two reservoirs. This new technology helped the operator overcome challenges and deliver improved service quality. Real-time data acquisition during the packer setting helps ensure correct inflation, and continuous monitoring of the isolated zone during the PBU process helps ensure data accuracy and defines the end of data acquisition time once radial flow has been observed in the pressure transient analysis; therefore, the points previously discussed strongly impact production by optimizing operation time. Avoiding the use of materials such as cement to isolate the mentioned zones made this operation environmentally friendly. The greatest value of this technology is that it makes real-time monitoring of both the upper and lower zones possible at the same time. The PBU test was successfully developed by determining reservoir pressure, skin, and flow regime of the near zone formation with precision and confidence, which helps the operator make decisions about future stimulations. High-pressure stimulation was achieved, which resulted in 460 BOPD over the initial production. Finally, a downhole ball-drop tool was effectively used to help ensure that packer setup was accurate and to reduce intervention time.
为了测量和分析储层压力、电导率、气/油比(GOR)和表皮值，有必要在井中相应的感兴趣区域进行压力累积(PBU)测试。本文介绍了连续油管(CT)实时光纤(RTFO)集成系统和可回收封隔器是如何在同一趟井中成功开发上部地层的PBU和下部地层的压力评估的决定因素。为了确保隔离和评估井中的每个高电位层，常规方法涉及多个程序，需要多次下入。使用CT RTFO (Vera et al. 2018)集成系统和可回收封隔器，只需要一次下入就可以完成PBU程序，其中包括对两个储层进行隔离和相应的测井。这项新技术帮助运营商克服了挑战，提高了服务质量。封隔器坐封过程中的实时数据采集有助于确保正确的膨胀，在PBU过程中对隔离层的持续监测有助于确保数据的准确性，并在压力瞬态分析中观察到径向流时定义数据采集的结束时间;因此，前面讨论的要点通过优化操作时间对产量有很大影响。避免使用水泥等材料来隔离上述区域，使该操作更加环保。该技术的最大价值在于它可以同时对上层和下层区域进行实时监控。PBU测试通过精确、可靠地确定储层压力、表皮和近层地层的流动状况，成功地开发了PBU测试，这有助于作业者对未来的增产措施做出决策。最终实现了高压增产，比初始产量增加了460桶/天。最后，有效地使用了井下投球工具，以确保封隔器安装的准确性，并缩短了修井时间。
{"title":"Real-Time Fiber-Optic Integrated System with Retrievable Packer Enables Single-Trip Dual-Zone Evaluation: Case Study, Eastern Foothills, Colombia","authors":"Vanessa Vera, Carlos A. Torres, E. Delgado, Carlos Pacheco, J. Higuera, Monica Torres","doi":"10.2118/191879-MS","DOIUrl":"https://doi.org/10.2118/191879-MS","url":null,"abstract":"\u0000 To measure and analyze reservoir pressure, conductivity, gas/oil ratio (GOR), and skin value, it is necessary to run a pressure buildup (PBU) test to the corresponding zone of interest in the well. This paper describes how the implementation of a coiled tubing (CT) real-time fiber-optic (RTFO) integrated system and a retrievable packer were determining factors to successfully develop both PBU in an upper formation and a pressure evaluation in the lower formation in the same run.\u0000 To help ensure isolation and evaluation of each high potential zone in the well, conventional methods involve multiple procedures requiring multiple runs. Using the CT RTFO (Vera et al. 2018) integrated system with a retrievable packer, only one run was necessary to complete the PBU program, which involves the isolation and corresponding log of two reservoirs.\u0000 This new technology helped the operator overcome challenges and deliver improved service quality. Real-time data acquisition during the packer setting helps ensure correct inflation, and continuous monitoring of the isolated zone during the PBU process helps ensure data accuracy and defines the end of data acquisition time once radial flow has been observed in the pressure transient analysis; therefore, the points previously discussed strongly impact production by optimizing operation time. Avoiding the use of materials such as cement to isolate the mentioned zones made this operation environmentally friendly. The greatest value of this technology is that it makes real-time monitoring of both the upper and lower zones possible at the same time.\u0000 The PBU test was successfully developed by determining reservoir pressure, skin, and flow regime of the near zone formation with precision and confidence, which helps the operator make decisions about future stimulations. High-pressure stimulation was achieved, which resulted in 460 BOPD over the initial production. Finally, a downhole ball-drop tool was effectively used to help ensure that packer setup was accurate and to reduce intervention time.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87313474","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}
Application of reservoir monitoring systems has great value in facilitating the understanding of reservoir behavior and complexity, efficient production optimization and reservoir management over time. The technology has been well accepted by oil and gas pioneers globally in the last 32 years (Australia, Venezuela, Colombia, Kuwait, Oman, Norway, China and USA). In the past 10 years, more than 1,000 wells have used reservoir monitoring systems to monitor the well and reservoir performance of coal seam gas (CSG) wells in Queensland. This paper presents technology, reservoir and production engineering analysis and failure mechanisms in more than 600 CSG wells in Queensland. This paper postulates the selection criteria for every specific application. Some services companies has a 8-year history of installing different types of gauges as one of the main reservoir monitoring technologies for different operators in Australia and New Zealand (The majority of this technology is based in the State of Queensland due to business and regulatory requirements). The application of technology helps CSG operators in the following capacities: Optimizing pump performance and water level monitoringOptimizing hydraulic fracture performance, ground water movement and modellingPressure data for the history matching process (Reservoir Engineering Application)Multizone pressure monitoring (gas injection performance, etc.) Specific application of the technology, findings during the installation, monitoring, operation, typical completion scheme and best practices for coal reservoir monitoring are summeraized in this paper.
{"title":"CSG Reservoir Monitoring Technology: Advantages, Challenges and Selection Criteria Queensland Case Study","authors":"A. Mortezapour, A. Bassat, E. Lean","doi":"10.2118/192044-MS","DOIUrl":"https://doi.org/10.2118/192044-MS","url":null,"abstract":"\u0000 Application of reservoir monitoring systems has great value in facilitating the understanding of reservoir behavior and complexity, efficient production optimization and reservoir management over time. The technology has been well accepted by oil and gas pioneers globally in the last 32 years (Australia, Venezuela, Colombia, Kuwait, Oman, Norway, China and USA). In the past 10 years, more than 1,000 wells have used reservoir monitoring systems to monitor the well and reservoir performance of coal seam gas (CSG) wells in Queensland. This paper presents technology, reservoir and production engineering analysis and failure mechanisms in more than 600 CSG wells in Queensland. This paper postulates the selection criteria for every specific application. Some services companies has a 8-year history of installing different types of gauges as one of the main reservoir monitoring technologies for different operators in Australia and New Zealand (The majority of this technology is based in the State of Queensland due to business and regulatory requirements). The application of technology helps CSG operators in the following capacities: Optimizing pump performance and water level monitoringOptimizing hydraulic fracture performance, ground water movement and modellingPressure data for the history matching process (Reservoir Engineering Application)Multizone pressure monitoring (gas injection performance, etc.)\u0000 Specific application of the technology, findings during the installation, monitoring, operation, typical completion scheme and best practices for coal reservoir monitoring are summeraized in this paper.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82539195","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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