In recent years, numerical fracturing simulation has seen an unprecedented emphasis on capturing the complexities that arise in hydraulic fracturing to better design and execute hydraulic fracturing jobs. As the need for more sophisticated simulators grows, so does the need for more sophisticated physical models that can be used to study the mechanics of the fracturing process under a controlled environment, and to validate the numerical predictions of advanced hydraulic fracturing simulators. We developed and utilized novel laboratory capabilities to perform an extensive set of fracturing experiments across various aspects of hydraulic fracture propagation including the effect of far-field stress contrast, rock mechanical heterogeneity, multi-well injection, borehole notching, fluid injection method, type of injection fluid, and interaction with natural fractures. Numerous direct observations and digital image analyses are documented to provide fundamental insights in hydraulic fracturing. As demonstrated through a few case studies from the literature, our laboratory experiments are very useful for validating hydraulic fracturing simulators due to the small-scale, two-dimensional (2-D) nature, controlled environment, and well-characterized properties of the test specimens used in the experiments.
{"title":"A Diverse Set of Validation Experiments for Hydraulic Fracturing Simulators","authors":"M. AlTammar, M. Sharma","doi":"10.2118/204577-ms","DOIUrl":"https://doi.org/10.2118/204577-ms","url":null,"abstract":"In recent years, numerical fracturing simulation has seen an unprecedented emphasis on capturing the complexities that arise in hydraulic fracturing to better design and execute hydraulic fracturing jobs. As the need for more sophisticated simulators grows, so does the need for more sophisticated physical models that can be used to study the mechanics of the fracturing process under a controlled environment, and to validate the numerical predictions of advanced hydraulic fracturing simulators. We developed and utilized novel laboratory capabilities to perform an extensive set of fracturing experiments across various aspects of hydraulic fracture propagation including the effect of far-field stress contrast, rock mechanical heterogeneity, multi-well injection, borehole notching, fluid injection method, type of injection fluid, and interaction with natural fractures. Numerous direct observations and digital image analyses are documented to provide fundamental insights in hydraulic fracturing. As demonstrated through a few case studies from the literature, our laboratory experiments are very useful for validating hydraulic fracturing simulators due to the small-scale, two-dimensional (2-D) nature, controlled environment, and well-characterized properties of the test specimens used in the experiments.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82050217","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. A. Mohamed, Mahmoud Mohamed Kheir, Ayman Abd El-ghany Al-Zahry, Ayman Salama, A. Ouda, Lotfi Ibrahim Abou El Maati, Mohamed Farouk Ahmed, Sally Ahmed Mohamed
Objectives / Scope: The main objective of this paper is to characterize the drilled shale formation in order to select and propose a "tailored" High Performance Low Invasion Fluids (HPLIF) system aided by Bridging Particles Optimization Tool (BPOT)(5),(6)(9)(11), capable of maximize hole stability in pressure depleted sands, allowing optimized well design through reactive and dispersible shale formations(7)(8) that eliminated one casing section, and to replace Oil Base Mud (OBM) and avoid its HSE issues related to use it, consequently, reduce formation damage, eliminate waste management cost, minimizing Non Productive Time (NPT) and finally enhances Drilling performance. Methods, Procedures, Process: This paper explain the reactivity information about Shale Samples recovered from different wells drilled in the-GOS-Egypt followed by extensive laboratory testing done(1) in order to characterize the main clay minerals presented in the samples using X-Ray Diffraction-(XRD) technology and their meso-and micro-structure by Scanning-Electron-Microscope-(SEM) and their reactivity to compare the inhibition efficiency of the proposed-(HPLIF)-System with Blank and Conventional Water-Base-Fluid-System. The reactivity of the cuttings was assessed by Dispersion, Swelling and Hardness tests. Field application experienced (HPLIF) System combined with Well-Bore Strengthening Materials (WSM) gives the required protection against induced losses and reducing the risk of differential sticking problems when mud overbalance is above 2500 psi(5), (6)(9)(11). Results, Observations, Conclusions: Compared with the use of conventional fluid systems, Field data demonstrated the successful application of (HPLIF) System combined with (WSM) and shows a great success during drilling through reactive clays, dispersive shale, naturally micro fractured(8), and depleted sand formations in many wells drilled in the GOS(2), (3), (4). Drilling operations reported no differential sticking, or wellbore instability issues even at highly mud overbalance or at highly deviated wells. The first challenged well R1-63 was drilled about 2391 ft, through 8.5" hole using 9.8-10.01 ppg using (HPLIF) system, penetrating through Thebes, Esna Shale, Sudr, Brown Lime Stone, Matulla, Nubia"A" Sand and Nubia "B" without any down-hole losses. Additionally, there was no sticking tendency experienced during drilling or while recording pressure points. The Non Productive Time NPT showed a reduction by about 19.2%. Finally, it ran and was cemented the "7" Liner in open hole successfully without problem. For the second challenged case well # 2, the Open hole was exposed to (HPLIF) water based mud system for a long period of time while rig repairing, rig switching, and during drilling operation. The well had 6" hole from 12,752 To/14,945 (2193.0ft) through Red bed, Thebes Esna, Sudr, Matulla and Nubia Sand formations with max inclination 68.6° and bottom hole temperature 325°F using 10.0-10.5 ppg (HPLIF)
{"title":"High-Performance-Low-Invasion Fluids Technology Enhances, Optimizes Drilling Efficiency in the Gulf of Suez - Egypt","authors":"Y. A. Mohamed, Mahmoud Mohamed Kheir, Ayman Abd El-ghany Al-Zahry, Ayman Salama, A. Ouda, Lotfi Ibrahim Abou El Maati, Mohamed Farouk Ahmed, Sally Ahmed Mohamed","doi":"10.2118/204743-ms","DOIUrl":"https://doi.org/10.2118/204743-ms","url":null,"abstract":"\u0000 \u0000 Objectives / Scope: The main objective of this paper is to characterize the drilled shale formation in order to select and propose a \"tailored\" High Performance Low Invasion Fluids (HPLIF) system aided by Bridging Particles Optimization Tool (BPOT)(5),(6)(9)(11), capable of maximize hole stability in pressure depleted sands, allowing optimized well design through reactive and dispersible shale formations(7)(8) that eliminated one casing section, and to replace Oil Base Mud (OBM) and avoid its HSE issues related to use it, consequently, reduce formation damage, eliminate waste management cost, minimizing Non Productive Time (NPT) and finally enhances Drilling performance.\u0000 Methods, Procedures, Process: This paper explain the reactivity information about Shale Samples recovered from different wells drilled in the-GOS-Egypt followed by extensive laboratory testing done(1) in order to characterize the main clay minerals presented in the samples using X-Ray Diffraction-(XRD) technology and their meso-and micro-structure by Scanning-Electron-Microscope-(SEM) and their reactivity to compare the inhibition efficiency of the proposed-(HPLIF)-System with Blank and Conventional Water-Base-Fluid-System. The reactivity of the cuttings was assessed by Dispersion, Swelling and Hardness tests. Field application experienced (HPLIF) System combined with Well-Bore Strengthening Materials (WSM) gives the required protection against induced losses and reducing the risk of differential sticking problems when mud overbalance is above 2500 psi(5), (6)(9)(11).\u0000 Results, Observations, Conclusions: Compared with the use of conventional fluid systems, Field data demonstrated the successful application of (HPLIF) System combined with (WSM) and shows a great success during drilling through reactive clays, dispersive shale, naturally micro fractured(8), and depleted sand formations in many wells drilled in the GOS(2), (3), (4). Drilling operations reported no differential sticking, or wellbore instability issues even at highly mud overbalance or at highly deviated wells. The first challenged well R1-63 was drilled about 2391 ft, through 8.5\" hole using 9.8-10.01 ppg using (HPLIF) system, penetrating through Thebes, Esna Shale, Sudr, Brown Lime Stone, Matulla, Nubia\"A\" Sand and Nubia \"B\" without any down-hole losses. Additionally, there was no sticking tendency experienced during drilling or while recording pressure points. The Non Productive Time NPT showed a reduction by about 19.2%. Finally, it ran and was cemented the \"7\" Liner in open hole successfully without problem. For the second challenged case well # 2, the Open hole was exposed to (HPLIF) water based mud system for a long period of time while rig repairing, rig switching, and during drilling operation. The well had 6\" hole from 12,752 To/14,945 (2193.0ft) through Red bed, Thebes Esna, Sudr, Matulla and Nubia Sand formations with max inclination 68.6° and bottom hole temperature 325°F using 10.0-10.5 ppg (HPLIF) ","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85935684","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. Asif, Mustafa Alaliwat, Jon E. Hansen, M. Sheshtawy
The main objective of the acoustic logging in 15K openhole multistage fracturing completions (OH MSFs) is to identify the fracture initiation points behind pipe and contributing fractures to gas production. The technique will also help to understand the integrity of the OH packers. A well was identified to be a candidate for assessment through such technique. The selected well was one of the early 15K OH MSF completions in the region that was successfully implemented with the goal of hydrocarbon production at sustained commercial rates from a gas formation. The candidate well was drilled horizontally to achieve maximum contact in a tight gas sandstone formation. Similar wells in the region have seen many challenges of formation breakdown due to high formation stresses. The objective of this work is to use the acoustic data to better characterize fracture properties. The deployment of acoustic log technology can provide information of fractures initiation, contribution for the production and the reliability of the isolation packers between the stages. The candidate well was completed with five stages open-hole fracturing completion. As the well is in an open hole environment, a typical PLT survey provides the contribution of individual port in the cumulative production but provides limited or no information of contributing fractures behind the pipe. The technique of acoustic logging helped to determine the fracture initiation points in different stages. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated. The use of acoustic logging has helped to better understand the factors influencing fracture initiation in tight gas sandstone reservoirs; resulting in a better understanding of fractures density and decisions on future openhole length, number of fracturing stages, packers and frac ports placement.
{"title":"Leveraging Acoustic Logging for Identification & Quantification of Induced Fractures","authors":"A. Asif, Mustafa Alaliwat, Jon E. Hansen, M. Sheshtawy","doi":"10.2118/204691-ms","DOIUrl":"https://doi.org/10.2118/204691-ms","url":null,"abstract":"\u0000 The main objective of the acoustic logging in 15K openhole multistage fracturing completions (OH MSFs) is to identify the fracture initiation points behind pipe and contributing fractures to gas production. The technique will also help to understand the integrity of the OH packers. A well was identified to be a candidate for assessment through such technique. The selected well was one of the early 15K OH MSF completions in the region that was successfully implemented with the goal of hydrocarbon production at sustained commercial rates from a gas formation.\u0000 The candidate well was drilled horizontally to achieve maximum contact in a tight gas sandstone formation. Similar wells in the region have seen many challenges of formation breakdown due to high formation stresses. The objective of this work is to use the acoustic data to better characterize fracture properties. The deployment of acoustic log technology can provide information of fractures initiation, contribution for the production and the reliability of the isolation packers between the stages.\u0000 The candidate well was completed with five stages open-hole fracturing completion. As the well is in an open hole environment, a typical PLT survey provides the contribution of individual port in the cumulative production but provides limited or no information of contributing fractures behind the pipe. The technique of acoustic logging helped to determine the fracture initiation points in different stages. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated.\u0000 The use of acoustic logging has helped to better understand the factors influencing fracture initiation in tight gas sandstone reservoirs; resulting in a better understanding of fractures density and decisions on future openhole length, number of fracturing stages, packers and frac ports placement.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86048959","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. Gryzlov, Liliya Mironova, S. Safonov, M. Arsalan
Modern challenges in reservoir management have recently faced new opportunities in production control and optimization strategies. These strategies in turn rely on the availability of monitoring equipment, which is used to obtain production rates in real-time with sufficient accuracy. In particular, a multiphase flow meter is a device for measuring the individual rates of oil, gas and water from a well in real-time without separating fluid phases. Currently, there are several technologies available on the market but multiphase flow meters generally incapable to handle all ranges of operating conditions with satisfactory accuracy in addition to being expensive to maintain. Virtual Flow Metering (VFM) is a mathematical technique for the indirect estimation of oil, gas and water flowrates produced from a well. This method uses more readily available data from conventional sensors, such as downhole pressure and temperature gauges, and calculates the multiphase rates by combining physical multiphase models, various measurement data and an optimization algorithm. In this work, a brief overview of the virtual metering methods is presented, which is followed by the application of several advanced machine-learning techniques for a specific case of multiphase production monitoring in a highly dynamic wellbore. The predictive capabilities of different types of machine learning instruments are explored using a model simulated production data. Also, the effect of measurement noise on the quality of estimates is considered. The presented results demonstrate that the data-driven methods are very capable to predict multiphase flow rates with sufficient accuracy and can be considered as a back-up solution for a conventional multiphase meter.
{"title":"Artificial Intelligence and Data Analytics for Virtual Flow Metering","authors":"A. Gryzlov, Liliya Mironova, S. Safonov, M. Arsalan","doi":"10.2118/204662-ms","DOIUrl":"https://doi.org/10.2118/204662-ms","url":null,"abstract":"\u0000 Modern challenges in reservoir management have recently faced new opportunities in production control and optimization strategies. These strategies in turn rely on the availability of monitoring equipment, which is used to obtain production rates in real-time with sufficient accuracy. In particular, a multiphase flow meter is a device for measuring the individual rates of oil, gas and water from a well in real-time without separating fluid phases. Currently, there are several technologies available on the market but multiphase flow meters generally incapable to handle all ranges of operating conditions with satisfactory accuracy in addition to being expensive to maintain.\u0000 Virtual Flow Metering (VFM) is a mathematical technique for the indirect estimation of oil, gas and water flowrates produced from a well. This method uses more readily available data from conventional sensors, such as downhole pressure and temperature gauges, and calculates the multiphase rates by combining physical multiphase models, various measurement data and an optimization algorithm.\u0000 In this work, a brief overview of the virtual metering methods is presented, which is followed by the application of several advanced machine-learning techniques for a specific case of multiphase production monitoring in a highly dynamic wellbore. The predictive capabilities of different types of machine learning instruments are explored using a model simulated production data. Also, the effect of measurement noise on the quality of estimates is considered. The presented results demonstrate that the data-driven methods are very capable to predict multiphase flow rates with sufficient accuracy and can be considered as a back-up solution for a conventional multiphase meter.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85106229","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Bahrain Field (the "Field"), discovered in 1932, is an asymmetric anticline trending in a North-South direction of the Kingdom of Bahrain. It is a geologically complex field with 16 multi-stack carbonate and sandstone reservoirs, most of them oil bearing. The fluids varying from shallow tarry oil in Aruma to dry gas in the Khuff and pre-Khuff reservoirs. The Field has more than 2000 wells of which 90% have good quality log data. The Ostracod and Magwa reservoirs are heterogeneous, layered tight reservoirs and have been on production since 1964. The Ostracod reservoir consists of very heterogeneous with limestone intervals intercalated between shale layers, with a total thickness of around 200 ft. The Magwa reservoir conformably underlies the Ostracod reservoir. The Ostracod averages 120 ft in thickness and is dominated by limestone with high porosity, low permeability, and variable water saturations. Core derived permeability measurements are usually less than 5 mD and porosities average 22%. Production performance of individual wells is extremely variable and in many cases appears to be at odds with log-calculated saturations. Wells having good oil saturation often produce water and wells with low oil saturation produce high volumes of oil. Several studies have been conducted in an attempt to understand and resolve this. The variability of oil saturation which has been mapped both laterally across the Field and vertically within wells, led to the question of what caused the variation in oil saturation. The variation is not a function of depth, which one might expect. Causes might include oil failure to migrate into certain reservoir compartments, a loss of the original charge to shallower reservoir or the oil charge been restricted by rock quality. This paper attempts to address the variability in saturations seen across the Field and link known productivity to the Petrophysical interpretations. Nuclear Magnetic Resonance (NMR) logs had been employed in a targeted area of the Field in order to investigate rock quality in an attempt to explain the oil saturation distribution. A small NMR core study was undertaken in order to calibrate the NMR log response. The NMR data had been initially processed with what was considered a representative cut-off for Middle East Carbaonte rocks. This core study resulted in a surprisingly low series of T2 cut-off. The NMR logs were reprocessed with the more representative T2 cut-off. The resulting bound and free fluid fractions seemed to explain the observed well production.
{"title":"Characterization of Tight Carbonate Reservoir by Using Nuclear Magnetic Resonance Log Analysis in the Bahrain Field","authors":"Rabab Al Saffar, Michael Dowen","doi":"10.2118/204781-ms","DOIUrl":"https://doi.org/10.2118/204781-ms","url":null,"abstract":"\u0000 The Bahrain Field (the \"Field\"), discovered in 1932, is an asymmetric anticline trending in a North-South direction of the Kingdom of Bahrain. It is a geologically complex field with 16 multi-stack carbonate and sandstone reservoirs, most of them oil bearing. The fluids varying from shallow tarry oil in Aruma to dry gas in the Khuff and pre-Khuff reservoirs. The Field has more than 2000 wells of which 90% have good quality log data.\u0000 The Ostracod and Magwa reservoirs are heterogeneous, layered tight reservoirs and have been on production since 1964. The Ostracod reservoir consists of very heterogeneous with limestone intervals intercalated between shale layers, with a total thickness of around 200 ft. The Magwa reservoir conformably underlies the Ostracod reservoir. The Ostracod averages 120 ft in thickness and is dominated by limestone with high porosity, low permeability, and variable water saturations. Core derived permeability measurements are usually less than 5 mD and porosities average 22%.\u0000 Production performance of individual wells is extremely variable and in many cases appears to be at odds with log-calculated saturations. Wells having good oil saturation often produce water and wells with low oil saturation produce high volumes of oil. Several studies have been conducted in an attempt to understand and resolve this.\u0000 The variability of oil saturation which has been mapped both laterally across the Field and vertically within wells, led to the question of what caused the variation in oil saturation. The variation is not a function of depth, which one might expect. Causes might include oil failure to migrate into certain reservoir compartments, a loss of the original charge to shallower reservoir or the oil charge been restricted by rock quality.\u0000 This paper attempts to address the variability in saturations seen across the Field and link known productivity to the Petrophysical interpretations. Nuclear Magnetic Resonance (NMR) logs had been employed in a targeted area of the Field in order to investigate rock quality in an attempt to explain the oil saturation distribution. A small NMR core study was undertaken in order to calibrate the NMR log response. The NMR data had been initially processed with what was considered a representative cut-off for Middle East Carbaonte rocks. This core study resulted in a surprisingly low series of T2 cut-off. The NMR logs were reprocessed with the more representative T2 cut-off. The resulting bound and free fluid fractions seemed to explain the observed well production.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89534530","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Kalgaonkar, M. Bataweel, M. Alkhowaildi, Q. Sahu
Gelled acid systems based upon gelation of hydrochloric acid (HCl) are used widely in acid stimulation treatments to prevent fluid leak-off into the high permeable zones of a reservoir. The gelled-up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron-based crosslinker, and a breaker chemical in addition to other additives, with the acid as the base fluid. The polymer-based systems can lead to damage to formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling or precipitation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper, we showcase a new nanoparticles-based gelled acid system that does not contain any polymer or iron-based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. With increase in the temperature and as the acid spends there is a viscosity increase. The viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation. As the acid further reacts and continues to spend, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to highlight the development of the nanoparticle-based acid diversion fluid. The gelation properties of the acid system, as a function of acid strength and temperature, are investigated. Static and dynamic gelation studies as a function of time, temperature and pH are reported. It is demonstrated that the viscosification property is a function of pH and the gelation occurs in a pH widow from 1 to 5 pH units. The gelation performance of the new system is evaluated at temperatures up to 300°F. The effect of different types of surface modification chemistries on the gelation properties is investigated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry; and therefore provides more control over the system performance. The new gelled acid system overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems; as it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer-based system.
{"title":"A Non-Damaging Gelled Acid System Based on Surface Modified Nanoparticles","authors":"R. Kalgaonkar, M. Bataweel, M. Alkhowaildi, Q. Sahu","doi":"10.2118/204716-ms","DOIUrl":"https://doi.org/10.2118/204716-ms","url":null,"abstract":"\u0000 Gelled acid systems based upon gelation of hydrochloric acid (HCl) are used widely in acid stimulation treatments to prevent fluid leak-off into the high permeable zones of a reservoir. The gelled-up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron-based crosslinker, and a breaker chemical in addition to other additives, with the acid as the base fluid. The polymer-based systems can lead to damage to formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling or precipitation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity.\u0000 In this paper, we showcase a new nanoparticles-based gelled acid system that does not contain any polymer or iron-based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. With increase in the temperature and as the acid spends there is a viscosity increase. The viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation. As the acid further reacts and continues to spend, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment.\u0000 Various experimental techniques were used to highlight the development of the nanoparticle-based acid diversion fluid. The gelation properties of the acid system, as a function of acid strength and temperature, are investigated. Static and dynamic gelation studies as a function of time, temperature and pH are reported. It is demonstrated that the viscosification property is a function of pH and the gelation occurs in a pH widow from 1 to 5 pH units. The gelation performance of the new system is evaluated at temperatures up to 300°F. The effect of different types of surface modification chemistries on the gelation properties is investigated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry; and therefore provides more control over the system performance.\u0000 The new gelled acid system overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems; as it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer-based system.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89024010","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 wellbore drilling, the drilling mud density needs to be carefully selected such that the mud pressure inside the wellbore will not exceed formation breakdown pressure to avoid wellbore fracturing and extensive mud losses. However, in the hydraulic fracturing treatment, the lesser the value of the formation breakdown pressure the more optimal is the operation. We found out in this study that the pumping schedule (e.g., pumping duration and pumping rate) are factors in optimizing the breakdown pressure. In addition, this work investigates the effects of the finite length between packers on the magnitude of the breakdown pressure in various geological formations. The time-dependent evolving stresses around the wellbore are solved in the framework of time-dependent poroelasticity theory. The breakdown pressure is predicted from the evolution of the circumferential effective stresses. The effects of injection rate, formation properties, borehole diameter and length, and pumping duration on the breakdown pressure are presented in the form of engineering charts, for representative in-situ stress.
{"title":"Engineering Charts for Predicting Breakdown Pressure for Finite-Length Wellbore Intervals","authors":"Yanhui Han, Shengli Chen, Y. Abousleiman","doi":"10.2118/204907-ms","DOIUrl":"https://doi.org/10.2118/204907-ms","url":null,"abstract":"\u0000 In wellbore drilling, the drilling mud density needs to be carefully selected such that the mud pressure inside the wellbore will not exceed formation breakdown pressure to avoid wellbore fracturing and extensive mud losses. However, in the hydraulic fracturing treatment, the lesser the value of the formation breakdown pressure the more optimal is the operation. We found out in this study that the pumping schedule (e.g., pumping duration and pumping rate) are factors in optimizing the breakdown pressure. In addition, this work investigates the effects of the finite length between packers on the magnitude of the breakdown pressure in various geological formations. The time-dependent evolving stresses around the wellbore are solved in the framework of time-dependent poroelasticity theory. The breakdown pressure is predicted from the evolution of the circumferential effective stresses. The effects of injection rate, formation properties, borehole diameter and length, and pumping duration on the breakdown pressure are presented in the form of engineering charts, for representative in-situ stress.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77364634","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}
Ruslan Kalabayev, E. Sukhova, Gadam Rovshenov, G. Gurbanov, Joel Gil, Roman Kontarev
Many oil producing wells, globally, experience sand production problems when reservoir rock consists of unconsolidated sand. Several wells in the Dzheitune oil field are experiencing a similar challenge. Production of formation fines and sand has caused accumulation of fill and wellbore equipment failures and has necessitated periodical and costly coiled tubing-assisted wellbore cleanout operations. A novel chemical treatment tested in the oil field to tackle the challenge led to positive results. A well with a relatively short target perforation interval was selected as a candidate for the trial sand conglomeration treatment to avoid any uncertainties related to zone coverage. Pre-requisite sand agglomeration and chemical-crude oil compatibility laboratory studies were carried out to optimize the main system and preflush fluid formulations. Once the laboratory testing was complete, a step-rate test was performed to determine the maximum injection rate below formation fracturing pressure. The chemical systems were prepared using standard blending equipment. The preflush fluid was injected to prepare the treated zone. The main fluid was then injected into the reservoir in several cycles at matrix rate by a bullheading process. Upon completion of the treatment, the well was shut in for several days for optimal agglomeration (conglomeration) before the well was slowly put on production. A long-term increase in the productivity index and sand-free flow rate with no damage to the wellbore or the reservoir were observed. The technology demonstrated its efficiency in preventing and controlling sand production; avoiding frequent, time-consuming, costly wellbore cleanout operations; and producing hydrocarbons at reduced drawdown pressure.
{"title":"Novel Sand Conglomeration Treatment Prevents Sand Production and Enhances Well Productivity: Offshore Caspian Case Study","authors":"Ruslan Kalabayev, E. Sukhova, Gadam Rovshenov, G. Gurbanov, Joel Gil, Roman Kontarev","doi":"10.2118/204714-ms","DOIUrl":"https://doi.org/10.2118/204714-ms","url":null,"abstract":"\u0000 Many oil producing wells, globally, experience sand production problems when reservoir rock consists of unconsolidated sand. Several wells in the Dzheitune oil field are experiencing a similar challenge. Production of formation fines and sand has caused accumulation of fill and wellbore equipment failures and has necessitated periodical and costly coiled tubing-assisted wellbore cleanout operations. A novel chemical treatment tested in the oil field to tackle the challenge led to positive results.\u0000 A well with a relatively short target perforation interval was selected as a candidate for the trial sand conglomeration treatment to avoid any uncertainties related to zone coverage. Pre-requisite sand agglomeration and chemical-crude oil compatibility laboratory studies were carried out to optimize the main system and preflush fluid formulations. Once the laboratory testing was complete, a step-rate test was performed to determine the maximum injection rate below formation fracturing pressure. The chemical systems were prepared using standard blending equipment. The preflush fluid was injected to prepare the treated zone. The main fluid was then injected into the reservoir in several cycles at matrix rate by a bullheading process. Upon completion of the treatment, the well was shut in for several days for optimal agglomeration (conglomeration) before the well was slowly put on production.\u0000 A long-term increase in the productivity index and sand-free flow rate with no damage to the wellbore or the reservoir were observed. The technology demonstrated its efficiency in preventing and controlling sand production; avoiding frequent, time-consuming, costly wellbore cleanout operations; and producing hydrocarbons at reduced drawdown pressure.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82595975","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}
Yessica Fransisca, Karinka Adiandra, V. Manurung, Laila Warkhaida, M. Arham, Y. Yanto, Dwi Hudya Febrianto, Achmad Yaser
This paper describes the combination of strategies deployed to optimize horizontal well placement in a 40 ft thick isotropic sand with very low resistivity contrast compared to an underlying anisotropic shale in Semoga field. These strategies were developed due to previously unsuccessful attempts to drill a horizontal well with multiple side-tracks that was finally drilled and completed as a high-inclined well. To maximize reservoir contact of the subject horizontal well, a new methodology on well placement was developed by applying lessons learned, taking into account the additional challenges within this well. The first approach was to conduct a thorough analysis on the previous inclined well to evaluate each formation layer’s anisotropy ratio to be used in an effective geosteering model that could better simulate the real time environment. Correct selections of geosteering tools based on comprehensive pre-well modelling was considered to ensure on-target landing section to facilitate an effective lateral section. A comprehensive geosteering pre-well model was constructed to guide real-time operations. In the subject horizontal well, landing strategy was analysed in four stages of anisotropy ratio. The lateral section strategy focused on how to cater for the expected fault and maintain the trajectory to maximize reservoir exposure. Execution of the geosteering operations resulted in 100% reservoir contact. By monitoring the behaviour of shale anisotropy ratio from resistivity measurements and gamma ray at-bit data while drilling, the subject well was precisely landed at 11.5 ft TVD below the top of target sand. In the lateral section, wellbore trajectory intersected two faults exhibiting greater associated throw compared to the seismic estimate. Resistivity geo-signal and azimuthal resistivity responses were used to maintain the wellbore attitude inside the target reservoir. In this case history well with a low resistivity contrast environment, this methodology successfully enabled efficient operations to land the well precisely at the target with minimum borehole tortuosity. This was achieved by reducing geological uncertainty due to anomalous resistivity data responding to shale electrical anisotropy. Recognition of these electromagnetic resistivity values also played an important role in identifying the overlain anisotropic shale layer, hence avoiding reservoir exit. This workflow also helped in benchmarking future horizontal well placement operations in Semoga Field. Technical Categories: Geosteering and Well Placement, Reservoir Engineering, Low resistivity Low Contrast Reservoir Evaluation, Real-Time Operations, Case Studies
{"title":"A Novel Workflow for Geosteering a Horizontal Well in a Low Resistivity Contrast Anisotropic Environment: A Case Study in Semoga Field, Indonesia","authors":"Yessica Fransisca, Karinka Adiandra, V. Manurung, Laila Warkhaida, M. Arham, Y. Yanto, Dwi Hudya Febrianto, Achmad Yaser","doi":"10.2118/204547-ms","DOIUrl":"https://doi.org/10.2118/204547-ms","url":null,"abstract":"\u0000 This paper describes the combination of strategies deployed to optimize horizontal well placement in a 40 ft thick isotropic sand with very low resistivity contrast compared to an underlying anisotropic shale in Semoga field. These strategies were developed due to previously unsuccessful attempts to drill a horizontal well with multiple side-tracks that was finally drilled and completed as a high-inclined well.\u0000 To maximize reservoir contact of the subject horizontal well, a new methodology on well placement was developed by applying lessons learned, taking into account the additional challenges within this well. The first approach was to conduct a thorough analysis on the previous inclined well to evaluate each formation layer’s anisotropy ratio to be used in an effective geosteering model that could better simulate the real time environment. Correct selections of geosteering tools based on comprehensive pre-well modelling was considered to ensure on-target landing section to facilitate an effective lateral section.\u0000 A comprehensive geosteering pre-well model was constructed to guide real-time operations. In the subject horizontal well, landing strategy was analysed in four stages of anisotropy ratio. The lateral section strategy focused on how to cater for the expected fault and maintain the trajectory to maximize reservoir exposure. Execution of the geosteering operations resulted in 100% reservoir contact. By monitoring the behaviour of shale anisotropy ratio from resistivity measurements and gamma ray at-bit data while drilling, the subject well was precisely landed at 11.5 ft TVD below the top of target sand. In the lateral section, wellbore trajectory intersected two faults exhibiting greater associated throw compared to the seismic estimate. Resistivity geo-signal and azimuthal resistivity responses were used to maintain the wellbore attitude inside the target reservoir.\u0000 In this case history well with a low resistivity contrast environment, this methodology successfully enabled efficient operations to land the well precisely at the target with minimum borehole tortuosity. This was achieved by reducing geological uncertainty due to anomalous resistivity data responding to shale electrical anisotropy. Recognition of these electromagnetic resistivity values also played an important role in identifying the overlain anisotropic shale layer, hence avoiding reservoir exit. This workflow also helped in benchmarking future horizontal well placement operations in Semoga Field.\u0000 Technical Categories: Geosteering and Well Placement, Reservoir Engineering, Low resistivity Low Contrast Reservoir Evaluation, Real-Time Operations, Case Studies","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73159359","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}
Yunlai Yang, Wei Li, F. Almalki, Maher I. Almarhoon
Real time lithological information at the drill bit is required for some important drilling operations, such as geo-steering and casing shoe positioning. This paper presents a novel tool "Petro-phone" for recording and processing drill bit sounds, which are generated by the drill bit cutting the rock, in order to provide real time lithological information for the rock at the drill bit. A prototype and a preliminary professional version of Petro-phone have been developed and field trialed. Petro-phone is a surface tool with its acoustic sensors attached to the top drive of a drill rig at some strategical locations for maximally picking up drill bit sounds. The drill bit sounds generated at the drill bit transmit along drill string and drive shaft to reach to the acoustic sensors. Since all the parts along the drill bit sound transmission pathway are made of steel, the drill bit sounds transmit efficiently from the source (drill bit) to the sensors. Preliminary results from two field trials show that drill bit sound patterns correlate with lithologies. The results also indicate that a parameter "Apparent Power" of drill bit sounds negatively correlates with gamma log. Due to its true real time nature, Petro-phone potentially has some real time applications, such as geo-steering, casing shoes positioning. Recorded drill bit sound can also potentially be used to derive lithological information, such as lithology type.
{"title":"A Tool for Derivation of Real Time Lithological Information from Drill Bit Sound","authors":"Yunlai Yang, Wei Li, F. Almalki, Maher I. Almarhoon","doi":"10.2118/204895-ms","DOIUrl":"https://doi.org/10.2118/204895-ms","url":null,"abstract":"\u0000 Real time lithological information at the drill bit is required for some important drilling operations, such as geo-steering and casing shoe positioning. This paper presents a novel tool \"Petro-phone\" for recording and processing drill bit sounds, which are generated by the drill bit cutting the rock, in order to provide real time lithological information for the rock at the drill bit. A prototype and a preliminary professional version of Petro-phone have been developed and field trialed. Petro-phone is a surface tool with its acoustic sensors attached to the top drive of a drill rig at some strategical locations for maximally picking up drill bit sounds. The drill bit sounds generated at the drill bit transmit along drill string and drive shaft to reach to the acoustic sensors. Since all the parts along the drill bit sound transmission pathway are made of steel, the drill bit sounds transmit efficiently from the source (drill bit) to the sensors. Preliminary results from two field trials show that drill bit sound patterns correlate with lithologies. The results also indicate that a parameter \"Apparent Power\" of drill bit sounds negatively correlates with gamma log. Due to its true real time nature, Petro-phone potentially has some real time applications, such as geo-steering, casing shoes positioning. Recorded drill bit sound can also potentially be used to derive lithological information, such as lithology type.","PeriodicalId":11320,"journal":{"name":"Day 3 Tue, November 30, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74973517","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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