John Michael Tesha, Derrick S. Dlamini, Edgar Christian Mapunda, Ashura Katunzi Kilewela
The formation of submicron-sized bubbles is frequently associated with the fragmentation of methane clathrate. A bubble refers to a pocket or a round particle of one substance trapped inside another. In most cases, these spherical pockets are made of gas trapped inside of a liquid. Usually, bubbles can lie underneath the surface of the liquid until the surface tension breaks and the gas escapes back into the atmosphere. Therefore, understanding the fluid dynamics behavior of the clathrate phase shift and enhancing the production efficiency of natural gas requires knowledge of the impact of submicron-sized bubbles on the clathrate fragmentation. In this scenario, molecular dynamics simulation (MDS) models were carried out to investigate the methane clathrate fragmentation rate with and without preexisting submicron-sized bubbles. The findings demonstrate layer-by-layer fragmentation of the methane clathrate cluster in the liquid phase. Furthermore, this mechanism shows temperature and submicron-sized bubble existence independent of simulation settings or conditions. However, because of the stability of the supersaturated methane solution for a long period, methane clathrate fragmentation does not always result in the formation of submicron-sized bubbles. It was observed that between the bubble (submicron-size) of methane and the cluster surface of methane clathrate, there is a steep slope of methane concentration. This results in the liquid phase efficiently decreasing the methane concentration and improving the migration of natural gas in different directions, hence the driving force increases for methane clathrate fragmentation. Our discoveries in this research show that the existence of submicron-sized bubbles near the surface of the methane clathrate can speed up the rate of intrinsic decomposition while decreasing the activation energy of methane clathrate fragmentation. The mass flow rate toward submicron-sized bubbles linearly correlates with the methane clathrate fragmentation rate. The mass flow rate is governed by the size of the submicron-sized bubbles and the spacing between the methane clathrate submicron-sized bubbles. Our results contribute to the in-depth knowledge of the fragmentation technique in the liquid phase for methane clathrates, which is critical in optimizing and designing effective gas clathrate development methods.
{"title":"An Investigation on the Impact of Submicron-Sized Bubbles on the Fragmentation of Methane Clathrates Using Molecular Dynamics Simulation","authors":"John Michael Tesha, Derrick S. Dlamini, Edgar Christian Mapunda, Ashura Katunzi Kilewela","doi":"10.2118/218399-pa","DOIUrl":"https://doi.org/10.2118/218399-pa","url":null,"abstract":"\u0000 The formation of submicron-sized bubbles is frequently associated with the fragmentation of methane clathrate. A bubble refers to a pocket or a round particle of one substance trapped inside another. In most cases, these spherical pockets are made of gas trapped inside of a liquid. Usually, bubbles can lie underneath the surface of the liquid until the surface tension breaks and the gas escapes back into the atmosphere. Therefore, understanding the fluid dynamics behavior of the clathrate phase shift and enhancing the production efficiency of natural gas requires knowledge of the impact of submicron-sized bubbles on the clathrate fragmentation. In this scenario, molecular dynamics simulation (MDS) models were carried out to investigate the methane clathrate fragmentation rate with and without preexisting submicron-sized bubbles. The findings demonstrate layer-by-layer fragmentation of the methane clathrate cluster in the liquid phase. Furthermore, this mechanism shows temperature and submicron-sized bubble existence independent of simulation settings or conditions. However, because of the stability of the supersaturated methane solution for a long period, methane clathrate fragmentation does not always result in the formation of submicron-sized bubbles. It was observed that between the bubble (submicron-size) of methane and the cluster surface of methane clathrate, there is a steep slope of methane concentration. This results in the liquid phase efficiently decreasing the methane concentration and improving the migration of natural gas in different directions, hence the driving force increases for methane clathrate fragmentation. Our discoveries in this research show that the existence of submicron-sized bubbles near the surface of the methane clathrate can speed up the rate of intrinsic decomposition while decreasing the activation energy of methane clathrate fragmentation. The mass flow rate toward submicron-sized bubbles linearly correlates with the methane clathrate fragmentation rate. The mass flow rate is governed by the size of the submicron-sized bubbles and the spacing between the methane clathrate submicron-sized bubbles. Our results contribute to the in-depth knowledge of the fragmentation technique in the liquid phase for methane clathrates, which is critical in optimizing and designing effective gas clathrate development methods.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"10 8","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139015877","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Prolonged waterflooding or polymer flooding in oil fields often exacerbates reservoir heterogeneity, leading to premature water breakthrough and high water cut, which significantly hinders efficient oilfield development. To address this issue, polymer gel particles have been prescribed to enhance sweep efficiency and augment waterflooding recovery by plugging preferential pathways within the reservoir. However, inherent weaknesses of polymer gel particles, such as fast water absorption and expansion rates in the initial stage and low post-expansion rates, make it difficult to balance in-depth transportation and plugging performance. Additionally, these gel particles are sensitive to ions in the formation water, resulting in reduced expansion rates under high-salinity conditions. Therefore, there are still challenges in the application of polymer gel particles for in-depth permeability control. In this study, a new type of delayed swelling and salt-resistant polymer gel particle was synthesized through inverse emulsion copolymerization. To achieve delayed swelling, we use a degradable crosslinker and hydrophobic monomer to enhance the crosslinked network density and hydrophobicity of gel particles. Our double crosslinked gel particles keep their original size until Day 2, then gradually swell up to 20 days in NaCl solution with a concentration of 15×104 mg·L−1 at 90°C. In comparison, the traditional single crosslinked gel particles show significant disparities in swelling behaviors and quickly swell when just dispersed in a 15×104 mg·L−1 NaCl solution at 90°C, maintaining roughly the same size over the testing period. Coreflooding experiments demonstrate that the residual resistance before and after aging increases from 2.37 to 6.82. The newly synthesized delayed swelling and salt-resistant polymer gel particles exhibit promising potential for overcoming the challenges associated with reservoir heterogeneity and high salinity.
{"title":"Development of Novel Delayed Swelling Polymer Gel Particles with Salt Resistance for Enhanced In-Depth Permeability Control","authors":"Yining Wu, Haiqing Zhang, Liyuan Zhang, Yongping Huang, Mingwei Zhao, Caili Dai","doi":"10.2118/218394-pa","DOIUrl":"https://doi.org/10.2118/218394-pa","url":null,"abstract":"\u0000 Prolonged waterflooding or polymer flooding in oil fields often exacerbates reservoir heterogeneity, leading to premature water breakthrough and high water cut, which significantly hinders efficient oilfield development. To address this issue, polymer gel particles have been prescribed to enhance sweep efficiency and augment waterflooding recovery by plugging preferential pathways within the reservoir. However, inherent weaknesses of polymer gel particles, such as fast water absorption and expansion rates in the initial stage and low post-expansion rates, make it difficult to balance in-depth transportation and plugging performance. Additionally, these gel particles are sensitive to ions in the formation water, resulting in reduced expansion rates under high-salinity conditions. Therefore, there are still challenges in the application of polymer gel particles for in-depth permeability control. In this study, a new type of delayed swelling and salt-resistant polymer gel particle was synthesized through inverse emulsion copolymerization. To achieve delayed swelling, we use a degradable crosslinker and hydrophobic monomer to enhance the crosslinked network density and hydrophobicity of gel particles. Our double crosslinked gel particles keep their original size until Day 2, then gradually swell up to 20 days in NaCl solution with a concentration of 15×104 mg·L−1 at 90°C. In comparison, the traditional single crosslinked gel particles show significant disparities in swelling behaviors and quickly swell when just dispersed in a 15×104 mg·L−1 NaCl solution at 90°C, maintaining roughly the same size over the testing period. Coreflooding experiments demonstrate that the residual resistance before and after aging increases from 2.37 to 6.82. The newly synthesized delayed swelling and salt-resistant polymer gel particles exhibit promising potential for overcoming the challenges associated with reservoir heterogeneity and high salinity.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"101 8","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139020137","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A new approach for the synthesis of bio-inspired polymer microcapsules used to encapsulate chemical additives and designed for small molecule release and delivery is shown here. The flexibility to design different microcapsules using an emulsion template results in various encapsulated additives for a new polymer technology platform. The base materials for encapsulation are polyaramids that are highly crosslinked membrane shells around an empty core. These empty capsules provide a carefully designed space to site-isolate chemical additives, various encapsulants for encapsulation, and delivery where needed. These microcapsules have demonstrated that after being formed from a simple one-pot synthesis between two immiscible solutions, a new method for encapsulation for applications in ordinary Portland cement is possible. The final product is a free-flowing solid that can be easily added to any fluid application. Experimental results show that when added to a basic cement slurry design, cement responds to the release of a salt accelerant as measured using standard oilfield equipment, like the pressurized consistometer, which measures changes in viscosity and thickening times. In one of many applications, the consistency of cement remains favorable at 20 Bc after adding encapsulated calcium chloride for up to 5 hours, for example. Over time, various capsules caused cement slurries to set at right angles at various thickening times with the controlled release of encapsulated calcium chloride. This new approach for encapsulation is promising for the chemical and energy field.
{"title":"New Approach to Encapsulation for Controlled Release of Chemical Additives","authors":"Elizabeth Q. Contreras","doi":"10.2118/213736-pa","DOIUrl":"https://doi.org/10.2118/213736-pa","url":null,"abstract":"\u0000 A new approach for the synthesis of bio-inspired polymer microcapsules used to encapsulate chemical additives and designed for small molecule release and delivery is shown here. The flexibility to design different microcapsules using an emulsion template results in various encapsulated additives for a new polymer technology platform. The base materials for encapsulation are polyaramids that are highly crosslinked membrane shells around an empty core. These empty capsules provide a carefully designed space to site-isolate chemical additives, various encapsulants for encapsulation, and delivery where needed. These microcapsules have demonstrated that after being formed from a simple one-pot synthesis between two immiscible solutions, a new method for encapsulation for applications in ordinary Portland cement is possible. The final product is a free-flowing solid that can be easily added to any fluid application. Experimental results show that when added to a basic cement slurry design, cement responds to the release of a salt accelerant as measured using standard oilfield equipment, like the pressurized consistometer, which measures changes in viscosity and thickening times. In one of many applications, the consistency of cement remains favorable at 20 Bc after adding encapsulated calcium chloride for up to 5 hours, for example. Over time, various capsules caused cement slurries to set at right angles at various thickening times with the controlled release of encapsulated calcium chloride. This new approach for encapsulation is promising for the chemical and energy field.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"942 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139019015","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Yunxing Duan, Xianshu Dong, Yang Hao, Yuping Fan, Xiaomin Ma, Lu Zhou
In drilling engineering, mudcake is formed when the drilling fluid invades the near-wellbore zone, which can reduce drilling fluid leakage and reservoir pollution and maintain wellbore stability. Exploring the method that can best represent the field working conditions to evaluate the mudcake is an urgent problem. At present, the macro-evaluation method cannot describe the characteristics of heterogeneity, particle accumulation, and porous media of mudcake. The micro-evaluation method needs local sampling, drying, curing, slicing, and other tedious disturbance treatments, which cannot reflect the overall characteristics of mudcake. To solve these problems, a novel technique for evaluating the pore structure of mudcake was established by taking nuclear magnetic resonance (NMR) T2 tests as the key mean and integrating high-pressure mercury injection tests, fluid isotope tracing, dynamic/static filtration experiment of drilling fluid, pore permeability parameter tests of core, and particle-size distribution tests of drilling fluid. The evaluation results of mudcake formed by drilling fluid static and dynamic filtration show that this technology can study the pore structure characteristics of the outer mudcake and intruded core and the distribution characteristics of the inner mudcake and filtrate in the intruded core. The novel evaluation technique has strong operability and less demand for experimental samples, which can study the micron-scale pore structure of mudcake and provide practical methods for drilling fluid system optimization and application effect evaluation, reservoir damage evaluation, and development or verification of the filtration model.
{"title":"A Novel Evaluation Technique for Mudcake of Drilling Fluid Based on the Nuclear Magnetic Resonance Method","authors":"Yunxing Duan, Xianshu Dong, Yang Hao, Yuping Fan, Xiaomin Ma, Lu Zhou","doi":"10.2118/217995-pa","DOIUrl":"https://doi.org/10.2118/217995-pa","url":null,"abstract":"\u0000 In drilling engineering, mudcake is formed when the drilling fluid invades the near-wellbore zone, which can reduce drilling fluid leakage and reservoir pollution and maintain wellbore stability. Exploring the method that can best represent the field working conditions to evaluate the mudcake is an urgent problem. At present, the macro-evaluation method cannot describe the characteristics of heterogeneity, particle accumulation, and porous media of mudcake. The micro-evaluation method needs local sampling, drying, curing, slicing, and other tedious disturbance treatments, which cannot reflect the overall characteristics of mudcake. To solve these problems, a novel technique for evaluating the pore structure of mudcake was established by taking nuclear magnetic resonance (NMR) T2 tests as the key mean and integrating high-pressure mercury injection tests, fluid isotope tracing, dynamic/static filtration experiment of drilling fluid, pore permeability parameter tests of core, and particle-size distribution tests of drilling fluid. The evaluation results of mudcake formed by drilling fluid static and dynamic filtration show that this technology can study the pore structure characteristics of the outer mudcake and intruded core and the distribution characteristics of the inner mudcake and filtrate in the intruded core. The novel evaluation technique has strong operability and less demand for experimental samples, which can study the micron-scale pore structure of mudcake and provide practical methods for drilling fluid system optimization and application effect evaluation, reservoir damage evaluation, and development or verification of the filtration model.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"269 ","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139023798","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Leopoldo Matias Ruiz Maraggi, Mark P. Walsh, Larry W. Lake
<p>Decline-curve models inherently assume that the bottomhole flowing pressure (BHP) is constant. This is a poor assumption for many unconventional wells. For this reason, the application of decline-curve models might lead to incorrect flow regime identification and estimated ultimate recovery (EUR). This work presents a novel technique that combines variable BHP conditions with decline-curve models and compares its results with traditional decline-curve analysis (DCA) for both synthetic and tight-oil wells.</p><p>Using superposition, we generate a synthetic rate example using the constant-pressure solution of the diffusivity equation for a slightly compressible fluid (decline-curve model) along with a BHP history. However, we validate the technique using bottomhole and initial reservoir pressures that contain errors. The algorithm consists of three sequential optimizations. In each optimization, the algorithm estimates (1) the decline-curve model parameters, (2) the BHP, and (3) the initial reservoir pressure. The result of the synthetic example leads to an accurate production history match and corrected estimates of the initial reservoir pressure and the BHP history. Finally, we compare the results of the technique with traditional DCA in terms of (a) the model parameters, (b) flow regime identification, (c) production history matches, and (d) EUR for tight-oil wells using three decline-curve models: 1D single-phase constant-pressure solution of the diffusivity equation for a slightly compressible fluid, logistic growth model, and Arps hyperbolic relation.</p><p>For the synthetic case, the algorithm estimates the model parameters and the true initial reservoir pressure within a 2% error. In addition, the method regenerates the true BHP history and provides an excellent production history match. The analysis of the tight-oil wells shows that the new approach clearly identifies the flow regimes present in the well, which can be difficult to detect using traditional DCA when the BHP varies. In contrast, the application of traditional DCA shows considerable errors in the estimation of the model’s parameters and a poor history match of the production data. Finally, this work shows that incorporating variable BHP into the decline-curve models leads to more accurate production history matches and EUR values compared to using only rate-time data.</p><p>This paper illustrates a workflow that incorporates variable BHP conditions for any decline-curve model. Moreover, the approach can handle errors in both the BHP and the initial reservoir pressure and provides corrected estimates of these variables. The technique is computationally fast and history matches and forecasts the production of unconventional wells more accurately than traditional DCA. The major contribution of this work is the remarkable simplicity yet robustness of our solution to variable-pressure DCA. Finally, we developed a web-based application to provide the readers with a hands-on exper
{"title":"A New Approach to Apply Decline-Curve Analysis for Tight-Oil Reservoirs Producing Under Variable Pressure Conditions","authors":"Leopoldo Matias Ruiz Maraggi, Mark P. Walsh, Larry W. Lake","doi":"10.2118/218016-pa","DOIUrl":"https://doi.org/10.2118/218016-pa","url":null,"abstract":"<p>Decline-curve models inherently assume that the bottomhole flowing pressure (BHP) is constant. This is a poor assumption for many unconventional wells. For this reason, the application of decline-curve models might lead to incorrect flow regime identification and estimated ultimate recovery (EUR). This work presents a novel technique that combines variable BHP conditions with decline-curve models and compares its results with traditional decline-curve analysis (DCA) for both synthetic and tight-oil wells.</p><p>Using superposition, we generate a synthetic rate example using the constant-pressure solution of the diffusivity equation for a slightly compressible fluid (decline-curve model) along with a BHP history. However, we validate the technique using bottomhole and initial reservoir pressures that contain errors. The algorithm consists of three sequential optimizations. In each optimization, the algorithm estimates (1) the decline-curve model parameters, (2) the BHP, and (3) the initial reservoir pressure. The result of the synthetic example leads to an accurate production history match and corrected estimates of the initial reservoir pressure and the BHP history. Finally, we compare the results of the technique with traditional DCA in terms of (a) the model parameters, (b) flow regime identification, (c) production history matches, and (d) EUR for tight-oil wells using three decline-curve models: 1D single-phase constant-pressure solution of the diffusivity equation for a slightly compressible fluid, logistic growth model, and Arps hyperbolic relation.</p><p>For the synthetic case, the algorithm estimates the model parameters and the true initial reservoir pressure within a 2% error. In addition, the method regenerates the true BHP history and provides an excellent production history match. The analysis of the tight-oil wells shows that the new approach clearly identifies the flow regimes present in the well, which can be difficult to detect using traditional DCA when the BHP varies. In contrast, the application of traditional DCA shows considerable errors in the estimation of the model’s parameters and a poor history match of the production data. Finally, this work shows that incorporating variable BHP into the decline-curve models leads to more accurate production history matches and EUR values compared to using only rate-time data.</p><p>This paper illustrates a workflow that incorporates variable BHP conditions for any decline-curve model. Moreover, the approach can handle errors in both the BHP and the initial reservoir pressure and provides corrected estimates of these variables. The technique is computationally fast and history matches and forecasts the production of unconventional wells more accurately than traditional DCA. The major contribution of this work is the remarkable simplicity yet robustness of our solution to variable-pressure DCA. Finally, we developed a web-based application to provide the readers with a hands-on exper","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"34 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140126559","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary Early detection of stuck-pipe incidents is crucial because of the enormous costs of recovering from such incidents. Previous studies have leaned significantly toward a physics-based or data science approach. However, both approaches have challenges, such as the uncertainty of the physics-based model and the lack of data in the data science approach. In this study. we propose a hybrid approach using physical insights and data science and discuss the possibility of stuck-pipe prediction. The proposed method comprises two steps. In the first step, a data-driven model with physical insights is trained using the historical data of the in-situ well to estimate some of the drilling variables. In the second step, the risk of stuck-pipe occurrence (hereafter referred to as sticking risk) is calculated based on the historical and current measured data and the estimation of the trained model. This approach is expected to overcome the limitations of the previous methods as it allows the construction of a detection model tuned to the in-situ well. In the case studies, models for estimating the topdrive torque and standpipe pressure were constructed. The performance of the models is discussed using actual drilling data from drilling fields, including 21 stuck-pipe incidents during drilling operations. The proposed method was first examined using short-term output. The output confirmed that the sticking risk increased shortly (up to 20 hours) before the stuck-pipe incident occurred in 15 cases. This increase in sticking risk was consistent with physical considerations. Subsequently, this study examined the long-term output over several months; this was rarely done in previous studies. Even within this long-term output, some cases had good performance with only a few false alarms, while others had problems with many false alarms. For cases of low performance, several model improvements, such as adding mud information or making the learning and threshold-setting methods more robust to outliers, were found to have the potential to improve performance. The novelty of our research lies in creating a broad framework for the stuck-pipe prediction by using both physical insights and data science methods. The proposed hybrid approach demonstrated the potential to reduce false alarms and improve interpretability compared with previous methods. The framework is highly extensible, and further performance improvements can be expected in the future.
{"title":"Hybrid Approach Using Physical Insights and Data Science for Stuck-Pipe Prediction","authors":"Tatsuya Kaneko, Tomoya Inoue, Yujin Nakagawa, Ryota Wada, Shungo Abe, Gota Yasutake, Kazuhiro Fujita","doi":"10.2118/218013-pa","DOIUrl":"https://doi.org/10.2118/218013-pa","url":null,"abstract":"Summary Early detection of stuck-pipe incidents is crucial because of the enormous costs of recovering from such incidents. Previous studies have leaned significantly toward a physics-based or data science approach. However, both approaches have challenges, such as the uncertainty of the physics-based model and the lack of data in the data science approach. In this study. we propose a hybrid approach using physical insights and data science and discuss the possibility of stuck-pipe prediction. The proposed method comprises two steps. In the first step, a data-driven model with physical insights is trained using the historical data of the in-situ well to estimate some of the drilling variables. In the second step, the risk of stuck-pipe occurrence (hereafter referred to as sticking risk) is calculated based on the historical and current measured data and the estimation of the trained model. This approach is expected to overcome the limitations of the previous methods as it allows the construction of a detection model tuned to the in-situ well. In the case studies, models for estimating the topdrive torque and standpipe pressure were constructed. The performance of the models is discussed using actual drilling data from drilling fields, including 21 stuck-pipe incidents during drilling operations. The proposed method was first examined using short-term output. The output confirmed that the sticking risk increased shortly (up to 20 hours) before the stuck-pipe incident occurred in 15 cases. This increase in sticking risk was consistent with physical considerations. Subsequently, this study examined the long-term output over several months; this was rarely done in previous studies. Even within this long-term output, some cases had good performance with only a few false alarms, while others had problems with many false alarms. For cases of low performance, several model improvements, such as adding mud information or making the learning and threshold-setting methods more robust to outliers, were found to have the potential to improve performance. The novelty of our research lies in creating a broad framework for the stuck-pipe prediction by using both physical insights and data science methods. The proposed hybrid approach demonstrated the potential to reduce false alarms and improve interpretability compared with previous methods. The framework is highly extensible, and further performance improvements can be expected in the future.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"64 5-6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135455373","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Qigui Tan, Bin Yang, Lijun You, Yili Kang, Haoping Peng, Fuquan Song, Chong Lin
Summary Salt dissolution induced by drill-in fluid loss is a frequent occurrence in saline-lacustrine reservoirs, which can potentially result in serious formation damage. In light of this, an experimental study was conducted to investigate the salt mineral dissolution and dynamic damage in the rock samples collected from a saline-lacustrine carbonate reservoir and the response of pore-fracture structures using the in-situ drill-in fluids. The study further involved analyzing the formation-damage-control (FDC) ability of the in-situ drill-in fluids. The results indicated that although salt dissolution significantly increased the pore size of the tight matrix and the width of natural fractures, improving the conductivity of seepage channels, the increase in pore-fracture size may have greatly aggravated the drill-in fluid loss during the process. The continuous serious filtrate loss, lower pressure-bearing capacity of the plugging zone, and lower permeability recovery rate (PRR) of rock indicated poor FDC performance of in-situ brine drilling fluids for the salt-dissolved core samples. The FDC performance of drill-in fluids for saline-lacustrine carbonate reservoirs was optimized based on the response of reservoir pore-fracture structure to salt dissolution and the theory of slightly underbalanced activity. The experimental results showed that the optimized drill-in fluids had better FDC ability, with an average PRR increase of 14.04%. Field application indicated that the optimized drill-in fluids reduced the drill-in fluid loss by 76.48%, shortened the drilling cycle by 45.20%, and increased the initial production capacity per well by 7.70%. This study can provide insightful guidance to optimize the FDC performance of drill-in fluids for saline-lacustrine hydrocarbon reservoirs during drilling.
{"title":"Drill-In Fluid Optimization for Formation Damage Control Considering Salt Dissolution in Saline-Lacustrine Reservoirs","authors":"Qigui Tan, Bin Yang, Lijun You, Yili Kang, Haoping Peng, Fuquan Song, Chong Lin","doi":"10.2118/218018-pa","DOIUrl":"https://doi.org/10.2118/218018-pa","url":null,"abstract":"Summary Salt dissolution induced by drill-in fluid loss is a frequent occurrence in saline-lacustrine reservoirs, which can potentially result in serious formation damage. In light of this, an experimental study was conducted to investigate the salt mineral dissolution and dynamic damage in the rock samples collected from a saline-lacustrine carbonate reservoir and the response of pore-fracture structures using the in-situ drill-in fluids. The study further involved analyzing the formation-damage-control (FDC) ability of the in-situ drill-in fluids. The results indicated that although salt dissolution significantly increased the pore size of the tight matrix and the width of natural fractures, improving the conductivity of seepage channels, the increase in pore-fracture size may have greatly aggravated the drill-in fluid loss during the process. The continuous serious filtrate loss, lower pressure-bearing capacity of the plugging zone, and lower permeability recovery rate (PRR) of rock indicated poor FDC performance of in-situ brine drilling fluids for the salt-dissolved core samples. The FDC performance of drill-in fluids for saline-lacustrine carbonate reservoirs was optimized based on the response of reservoir pore-fracture structure to salt dissolution and the theory of slightly underbalanced activity. The experimental results showed that the optimized drill-in fluids had better FDC ability, with an average PRR increase of 14.04%. Field application indicated that the optimized drill-in fluids reduced the drill-in fluid loss by 76.48%, shortened the drilling cycle by 45.20%, and increased the initial production capacity per well by 7.70%. This study can provide insightful guidance to optimize the FDC performance of drill-in fluids for saline-lacustrine hydrocarbon reservoirs during drilling.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"129 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135566148","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary Hydraulic fracturing technology is an effective measure that can improve oil and gas production and achieve enormous economic benefits owing to it phenomenally increasing the oil recovery from the low intrinsic permeability of the compact rock. Good placement and distribution of the proppant in the hydraulic fractures can provide successful stimulation for a well, which is essential for applying the hydraulic fracturing process. Previous studies extensively explored proppant placement, distribution, and operational factors in simplified smooth surface fracture models. However, the operational factors such as pump rate, proppant concentration, proppant size, fluid viscosity, and inlet condition (pulse time) involved in proppant placement and distribution in realistic rough surfaces of fractures are not clearly understood. In particular, the law of proppant transport in a two-sided rough surface of fracture with changes in the aforementioned operational factors was unclear. Hence, in this study, we investigated the effect of these operational factors on proppant placement and transport in both the smooth surface fracture model and the two-sided rough surface fracture model. The results suggested that the traditional law of proppant transport drawn on the smooth surface fracture model did not apply to the two-sided rough surface model. It is suggested that selecting corresponding variables was needed to reduce the risk of proppant bridging and offer a better channel ratio.
{"title":"Visual Laboratory Tests: Effect of Operational Parameters on Proppant Transport in a 3D Printed Vertical Hydraulic Fracture with Two-Sided Rough Surfaces","authors":"Jun Li, Xu Han, Siyuan He, Mingyi Wu, Xinqian Lu","doi":"10.2118/218007-pa","DOIUrl":"https://doi.org/10.2118/218007-pa","url":null,"abstract":"Summary Hydraulic fracturing technology is an effective measure that can improve oil and gas production and achieve enormous economic benefits owing to it phenomenally increasing the oil recovery from the low intrinsic permeability of the compact rock. Good placement and distribution of the proppant in the hydraulic fractures can provide successful stimulation for a well, which is essential for applying the hydraulic fracturing process. Previous studies extensively explored proppant placement, distribution, and operational factors in simplified smooth surface fracture models. However, the operational factors such as pump rate, proppant concentration, proppant size, fluid viscosity, and inlet condition (pulse time) involved in proppant placement and distribution in realistic rough surfaces of fractures are not clearly understood. In particular, the law of proppant transport in a two-sided rough surface of fracture with changes in the aforementioned operational factors was unclear. Hence, in this study, we investigated the effect of these operational factors on proppant placement and transport in both the smooth surface fracture model and the two-sided rough surface fracture model. The results suggested that the traditional law of proppant transport drawn on the smooth surface fracture model did not apply to the two-sided rough surface model. It is suggested that selecting corresponding variables was needed to reduce the risk of proppant bridging and offer a better channel ratio.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"9 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135371874","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abdulaziz A. Almakimi, Junchen Liu, Baojun Bai, I. Hussein
Preformed particle gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGs’ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGs’ penetration into the matrix under different sets of conditions. The filtration regimes were defined by filtration curves, and the gel damage on the matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particles’ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements. The results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particles’ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particles’ further penetration into the carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50–70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable but conditionally treatable.
预制颗粒凝胶（PPG）已被广泛应用于控制成熟油田中具有裂缝或类似裂缝特征的过量产水，尤其是在砂岩中，但对碳酸盐岩的应用却很有限。然而，PPG 对邻近基质的潜在破坏可能会带来负面影响，这也是一个重要的问题。本文全面评估了 PPG 对碳酸盐基质的潜在破坏，并寻求设计优化方案。通过过滤试验来比较 PPG 在不同条件下对基体的渗透情况。根据过滤曲线确定过滤条件，并根据渗透性测量结果确定凝胶对基质的破坏程度。实验还研究了氧化剂作为修复方法消除损伤的效率。根据对过滤测试结果和渗透性测量结果的分析，对凝胶颗粒在碳酸盐基质中的侵入和堵塞行为进行了定性描述。结果表明，根据凝胶颗粒对注入压力和流出流速的反应，膨胀凝胶过滤曲线可分为三个区域：过滤前结饼阶段、过滤结饼阶段和稳定阶段。PPG 可以在岩石表面形成滤饼，阻止颗粒进一步渗透到碳酸盐基质中，而且渗透范围只限于几毫米以内。在较高压力值（700 psi）下，最小的凝胶颗粒（50-70 US 目）更容易形成外部和内部滤饼，从而对基质造成更大的破坏。为了在过滤测试后恢复基质的渗透性，氧化剂浸泡被证明是一种可靠的解决方案。总之，研究结果表明，凝胶注入引起的无意基质渗透性破坏一般是不可避免的，但可以有条件地加以处理。
{"title":"Investigation of Carbonate Matrix Damage and Remediation Methods for Preformed Particle Gel Conformance Control Treatments","authors":"Abdulaziz A. Almakimi, Junchen Liu, Baojun Bai, I. Hussein","doi":"10.2118/210311-pa","DOIUrl":"https://doi.org/10.2118/210311-pa","url":null,"abstract":"Preformed particle gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGs’ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGs’ penetration into the matrix under different sets of conditions. The filtration regimes were defined by filtration curves, and the gel damage on the matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particles’ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements. The results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particles’ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particles’ further penetration into the carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50–70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable but conditionally treatable.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"68 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139301611","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200°F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300°F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants’ thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionic-anionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316°F to 348°F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.
{"title":"Nonionic Surfactant Blends for Enhanced Oil Recovery in High-Temperature Eagle Ford Reservoir","authors":"Elsie B. Ladan, David S. Schechter","doi":"10.2118/218382-pa","DOIUrl":"https://doi.org/10.2118/218382-pa","url":null,"abstract":"Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200°F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300°F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants’ thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionic-anionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316°F to 348°F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"208 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139304580","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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