S. S. Zhu, M. Antoniv, N. Saadoun, G. Thomas, M. Poitzsch, H. Kwak, A. Yousef
Drill cuttings logging (mud logging) is a technology with great potential to deliver formation evaluation and completion efficiency. However, the conventional mud logging technology determines the cutting sample depth using the lag time of the cutting’s return trip, which results in depth uncertainties of ±20 ft or more. We previously proposed to tag cuttings at the bit face with penetrating, impregnating polymeric NanoTags and to determine the cuttings’ depth using the NanoTag’s downward trip time, which could reduce the depth uncertainties to ±1–2 ft. The first field test to test the first generation of NanoTags was completed in December 2019. In that test, the signals of the NanoTags in the cuttings were detected using pyrolysis gas chromatography mass spectrometry (Py-GC/MS) analysis. The second field test for the development of this technology was performed in 2022 using a new generation of optical NanoTags that encapsulated a rhodamine dye. A detection method was also developed to analyze the optical tag on cuttings semiquantitatively using a fluorescent microscope and ImageJ software. Our results suggest that the depth determined by our tagging technology is accurate and correlates well with the mud logging data; the results also indicated that the optimal gap time between each tag injection should be greater than 10 minutes.
{"title":"Encapsulated Fluorescent Tags to Label Drill Cuttings for Improved Depth Correlation: A Field Application","authors":"S. S. Zhu, M. Antoniv, N. Saadoun, G. Thomas, M. Poitzsch, H. Kwak, A. Yousef","doi":"10.2118/221466-pa","DOIUrl":"https://doi.org/10.2118/221466-pa","url":null,"abstract":"\u0000 Drill cuttings logging (mud logging) is a technology with great potential to deliver formation evaluation and completion efficiency. However, the conventional mud logging technology determines the cutting sample depth using the lag time of the cutting’s return trip, which results in depth uncertainties of ±20 ft or more. We previously proposed to tag cuttings at the bit face with penetrating, impregnating polymeric NanoTags and to determine the cuttings’ depth using the NanoTag’s downward trip time, which could reduce the depth uncertainties to ±1–2 ft. The first field test to test the first generation of NanoTags was completed in December 2019. In that test, the signals of the NanoTags in the cuttings were detected using pyrolysis gas chromatography mass spectrometry (Py-GC/MS) analysis. The second field test for the development of this technology was performed in 2022 using a new generation of optical NanoTags that encapsulated a rhodamine dye. A detection method was also developed to analyze the optical tag on cuttings semiquantitatively using a fluorescent microscope and ImageJ software. Our results suggest that the depth determined by our tagging technology is accurate and correlates well with the mud logging data; the results also indicated that the optimal gap time between each tag injection should be greater than 10 minutes.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"4 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141393225","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}
Preformed particulate gel (PPG) has emerged as a widely utilized lost circulation material in deep oil and gas drilling operations. The objective of our study was to devise a high-strength preformed particle gel (HSPPG) specifically designed to address drilling fluid loss in high-temperature fractured formations. To achieve this, a comprehensive set of laboratory experiments was conducted to assess the swelling and rheological properties of HSPPG under various conditions, and these investigations aimed to provide deeper insights into the pressure-bearing mechanism exhibited by HSPPG. The synthesis of HSPPG involved the copolymerization of acrylamide (AM) and N-hydroxymethacrylamide (NMA) molecular chains, catalyzed by organic peroxides, to form the primary network. Additionally, to enhance its temperature resistance, urea-formaldehyde (UF) resin, known for its superior thermal stability, was incorporated into the secondary network. This unique combination of primary and secondary networks imparted remarkable thermal endurance and structural stability to the resulting HSPPG. The swelling and rheological experiments revealed that HSPPG, with a particle size of 1000 µm, exhibited an equilibrium swelling rate (SR) value of 30.55 and a storage modulus (G’) of 1050 Pa at 120℃. These findings attested to its excellent temperature resistance and structural stability. Furthermore, when subjected to a sodium chloride solution at a temperature of 120℃ and a concentration of 25.0%, HSPPG achieved equilibrium swelling with an SR value of 24.93 and a G’ of approximately 7000 Pa. This significant increase in structural strength was attributed to charge shielding within the highly concentrated brine environment. In the plugging experiments, a wedge-shaped slit with an inlet of 3 mm and an outlet of 1 mm was successfully blocked using a concentration of 4% of HSPPG with a particle size of 1000 μm. The blocking strength achieved was 8.06 MPa. The results of these experiments, as well as the observed filling and plugging state of HSPPG in steel fractured cores, indicated that HSPPG possesses the properties of water absorption, swelling, and extrusion filling. These attributes facilitate the effective formation of a dense blocking layer within the fracture space, exhibiting excellent pressure-bearing capacity. In conclusion, the HSPPG developed in this study represents an advanced swellable granular plugging agent with excellent swelling capacity and structural strength at high temperatures. It offers an ideal solution to mitigate drilling fluid loss from fractured formations under high-temperature and high-salinity conditions.
{"title":"Experimental Study of the Swelling and Rheological Properties of a High-Strength Preformed Particle Gel Lost Circulation Material","authors":"Yuecheng Zhu, Yingrui Bai, Jinsheng Sun, K. Lv","doi":"10.2118/221465-pa","DOIUrl":"https://doi.org/10.2118/221465-pa","url":null,"abstract":"\u0000 Preformed particulate gel (PPG) has emerged as a widely utilized lost circulation material in deep oil and gas drilling operations. The objective of our study was to devise a high-strength preformed particle gel (HSPPG) specifically designed to address drilling fluid loss in high-temperature fractured formations. To achieve this, a comprehensive set of laboratory experiments was conducted to assess the swelling and rheological properties of HSPPG under various conditions, and these investigations aimed to provide deeper insights into the pressure-bearing mechanism exhibited by HSPPG. The synthesis of HSPPG involved the copolymerization of acrylamide (AM) and N-hydroxymethacrylamide (NMA) molecular chains, catalyzed by organic peroxides, to form the primary network. Additionally, to enhance its temperature resistance, urea-formaldehyde (UF) resin, known for its superior thermal stability, was incorporated into the secondary network. This unique combination of primary and secondary networks imparted remarkable thermal endurance and structural stability to the resulting HSPPG. The swelling and rheological experiments revealed that HSPPG, with a particle size of 1000 µm, exhibited an equilibrium swelling rate (SR) value of 30.55 and a storage modulus (G’) of 1050 Pa at 120℃. These findings attested to its excellent temperature resistance and structural stability. Furthermore, when subjected to a sodium chloride solution at a temperature of 120℃ and a concentration of 25.0%, HSPPG achieved equilibrium swelling with an SR value of 24.93 and a G’ of approximately 7000 Pa. This significant increase in structural strength was attributed to charge shielding within the highly concentrated brine environment. In the plugging experiments, a wedge-shaped slit with an inlet of 3 mm and an outlet of 1 mm was successfully blocked using a concentration of 4% of HSPPG with a particle size of 1000 μm. The blocking strength achieved was 8.06 MPa. The results of these experiments, as well as the observed filling and plugging state of HSPPG in steel fractured cores, indicated that HSPPG possesses the properties of water absorption, swelling, and extrusion filling. These attributes facilitate the effective formation of a dense blocking layer within the fracture space, exhibiting excellent pressure-bearing capacity. In conclusion, the HSPPG developed in this study represents an advanced swellable granular plugging agent with excellent swelling capacity and structural strength at high temperatures. It offers an ideal solution to mitigate drilling fluid loss from fractured formations under high-temperature and high-salinity conditions.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"57 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141416033","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 integration of surveillance data analysis, encompassing wellbore pressure, fluid flow rate, tracer injection, and recovery, is pivotal in deciphering the dynamic behavior of wells within a geothermal field. This comprehensive study focuses on the interconnectivity between producers, gauged by the reciprocal-productivity index (RPI), and the synergy between producers and injectors, assessed through capacitance-resistance modeling (CRM). The modified-Hall analysis further corroborates the performance metrics of both injectors and producers, thereby reinforcing operational excellence. These methodologies and related analytical tools are instrumental in refining field management practices. Executing meticulous tracer tests and subsequent analyses is crucial in validating the CRM’s applicability in the field. The fusion of these investigative techniques solidifies the role of CRM in managing geothermal reservoirs. Additionally, this study sheds light on the potential compartmentalization within the reservoir and monitors the evolving performance of producers and injectors over time. Utilizing a suite of analytical tools, including RPI, CRM, and modified-Hall analysis, provides a holistic insight into the reservoir dynamics at the Alaşehir field in Türkiye, ensuring a sustainable and optimized exploitation of geothermal energy.
{"title":"Surveillance Data Analysis Reveals Well Performance and Reservoir Connectivity: A Case Study in Alasehir Geothermal Field","authors":"Hakki Aydin, C. Temizel, C. S. Kabir","doi":"10.2118/221454-pa","DOIUrl":"https://doi.org/10.2118/221454-pa","url":null,"abstract":"\u0000 The integration of surveillance data analysis, encompassing wellbore pressure, fluid flow rate, tracer injection, and recovery, is pivotal in deciphering the dynamic behavior of wells within a geothermal field. This comprehensive study focuses on the interconnectivity between producers, gauged by the reciprocal-productivity index (RPI), and the synergy between producers and injectors, assessed through capacitance-resistance modeling (CRM). The modified-Hall analysis further corroborates the performance metrics of both injectors and producers, thereby reinforcing operational excellence. These methodologies and related analytical tools are instrumental in refining field management practices.\u0000 Executing meticulous tracer tests and subsequent analyses is crucial in validating the CRM’s applicability in the field. The fusion of these investigative techniques solidifies the role of CRM in managing geothermal reservoirs. Additionally, this study sheds light on the potential compartmentalization within the reservoir and monitors the evolving performance of producers and injectors over time. Utilizing a suite of analytical tools, including RPI, CRM, and modified-Hall analysis, provides a holistic insight into the reservoir dynamics at the Alaşehir field in Türkiye, ensuring a sustainable and optimized exploitation of geothermal energy.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"44 15","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141403369","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}
Polymer flooding in deep reservoir profile control presents challenges in balancing injectivity and effective mobility control. To address this, we propose a solution by utilizing a microencapsulated polymer that can be easily injected and thickens over time. However, limited research has been conducted on the flow characteristics and the impact on oil mobilization by such profile control agents. In this study, we approximately simulated the time-varying flow process of microencapsulated polymer through in-situ triggered experiments at high temperature and pressure. The flow characteristics and oil displacement mechanism of the microencapsulated polymer under different trigger times were analyzed, and the displacement efficiency during the triggered viscosity enhancement process in porous media was quantitatively evaluated. The experimental results reveal that microencapsulated polymer exhibits a dual mechanism of near-wellbore reservoir particle temporary plugging and deep formation consistency control mechanisms. The transient aggregation of capsule particles alters the flow path, intensifying after expansion. The interaction between the microcapsule particles and the partially released polymer further enhances the resistance-enhancing property of the solution. The viscosity-enhanced microencapsulated polymer fluid improves the displacement efficiency. Microscopic oil displacement and coreflooding experiments resulted in a decrease in oil saturation of 39.5 and 18.33%, respectively. This study provides valuable microscopic insights into the flow behavior and oil displacement performance of microencapsulated polymer, offering essential guidance for optimizing oil reservoir extraction strategies.
{"title":"Visualization Experimental Study on In-Situ Triggered Displacement Mechanism by Microencapsulated Polymer in Porous Media","authors":"Yongsheng Liu, Bei Wei, Xulong Cao, Kaoping Song, Fuqing Yuan, Yu Xue, Jianyong Wang, Lei Tang, Yongge Liu, Zhijie Wei, Jian Zhang, Jian Hou","doi":"10.2118/221460-pa","DOIUrl":"https://doi.org/10.2118/221460-pa","url":null,"abstract":"\u0000 Polymer flooding in deep reservoir profile control presents challenges in balancing injectivity and effective mobility control. To address this, we propose a solution by utilizing a microencapsulated polymer that can be easily injected and thickens over time. However, limited research has been conducted on the flow characteristics and the impact on oil mobilization by such profile control agents. In this study, we approximately simulated the time-varying flow process of microencapsulated polymer through in-situ triggered experiments at high temperature and pressure. The flow characteristics and oil displacement mechanism of the microencapsulated polymer under different trigger times were analyzed, and the displacement efficiency during the triggered viscosity enhancement process in porous media was quantitatively evaluated. The experimental results reveal that microencapsulated polymer exhibits a dual mechanism of near-wellbore reservoir particle temporary plugging and deep formation consistency control mechanisms. The transient aggregation of capsule particles alters the flow path, intensifying after expansion. The interaction between the microcapsule particles and the partially released polymer further enhances the resistance-enhancing property of the solution. The viscosity-enhanced microencapsulated polymer fluid improves the displacement efficiency. Microscopic oil displacement and coreflooding experiments resulted in a decrease in oil saturation of 39.5 and 18.33%, respectively. This study provides valuable microscopic insights into the flow behavior and oil displacement performance of microencapsulated polymer, offering essential guidance for optimizing oil reservoir extraction strategies.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"17 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141276455","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}
Alkali-surfactant-polymer (ASP) flooding has achieved highly enhanced oil recovery (EOR) in the Daqing Oil Field; however, there are concerns about synthetic surfactants owing to their high cost and difficulty in biodegradation. Cheap biosurfactants conform to human concepts of green circular economy; however, known biosurfactants, as well as their mixtures with alkali, cannot reduce water/oil interfacial tension (IFT) to ultralow values below 0.01 mN/m, which is necessary for ASP flooding to effectively mobilize residual oil. Therefore, we investigate the feasibility of partially replacing synthetic surfactants with biosurfactants rather than completely replacing them to improve ASP flooding. First, through a series of IFT tests, a blend of rhamnolipids (RLs) and alkylbenzene sulfonate (ABS) in a 1:1 mass ratio is determined to be the optimal mixed surfactant and labeled RL/ABS-opt. Second, the interfacial activities, phase behaviors, and wettability alteration capabilities of ASP solutions with RL/ABS-opt are studied. Then, 1.0 wt% NaOH and 0.2 wt% RL/ABS-opt are determined to construct a new ASP system. Subsequently, the waterflooded cores are displaced using the new and the classical ASP systems. Based on the promising experimental results, the new ASP system floods a test block of 56 wells for 3 years. The EOR and surfactant costs are calculated to determine the technical and economic effects. Finally, the concentrations of surfactants before and after activated sludge treatment (AST) are tested by spectrophotometry to verify the biodegradability of RLs better than that of ABS. The laboratory and field results indicate that more biosurfactants and fewer synthetic surfactants could improve ASP flooding to be more environmentally friendly and cost-effective with a higher EOR.
碱-表面活性剂-聚合物（ASP）水淹法在大庆油田实现了高采收率（EOR）；然而，合成表面活性剂因其成本高、生物降解困难而备受关注。廉价的生物表面活性剂符合人类绿色循环经济的理念；然而，已知的生物表面活性剂及其与碱的混合物无法将水/油界面张力（IFT）降至 0.01 mN/m 以下的超低值，而这正是 ASP 淹没有效动员剩余油所必需的。因此，我们研究了用生物表面活性剂部分替代合成表面活性剂而非完全替代合成表面活性剂来改善 ASP 淹没的可行性。首先，通过一系列 IFT 测试，确定鼠李糖脂（RLs）和烷基苯磺酸盐（ABS）以 1:1 的质量比混合为最佳混合表面活性剂，并标记为 RL/ABS-opt。其次，研究了含有 RL/ABS-opt 的 ASP 溶液的界面活性、相行为和润湿性改变能力。然后，确定使用 1.0 wt% NaOH 和 0.2 wt% RL/ABS-opt 构建新的 ASP 系统。随后，使用新的和经典的 ASP 系统对注水岩心进行了置换。基于良好的实验结果，新的 ASP 系统对 56 口井进行了为期 3 年的灌水试验。计算了 EOR 和表面活性剂成本，以确定技术和经济效果。最后，通过分光光度法测试了活性污泥处理（AST）前后表面活性剂的浓度，以验证 RLs 的生物降解性优于 ABS。实验室和现场结果表明，使用更多的生物表面活性剂和更少的合成表面活性剂可以改善 ASP 的淹没情况，使其更环保、更具成本效益和更高的 EOR。
{"title":"More Biosurfactants and Fewer Synthetic Surfactants to Improve Alkali-Surfactant-Polymer Flooding: Feasibility Study and Large-Scale Field Application","authors":"Yeliang Dong, Dexin Liu, Yu Fan","doi":"10.2118/221458-pa","DOIUrl":"https://doi.org/10.2118/221458-pa","url":null,"abstract":"\u0000 Alkali-surfactant-polymer (ASP) flooding has achieved highly enhanced oil recovery (EOR) in the Daqing Oil Field; however, there are concerns about synthetic surfactants owing to their high cost and difficulty in biodegradation. Cheap biosurfactants conform to human concepts of green circular economy; however, known biosurfactants, as well as their mixtures with alkali, cannot reduce water/oil interfacial tension (IFT) to ultralow values below 0.01 mN/m, which is necessary for ASP flooding to effectively mobilize residual oil. Therefore, we investigate the feasibility of partially replacing synthetic surfactants with biosurfactants rather than completely replacing them to improve ASP flooding. First, through a series of IFT tests, a blend of rhamnolipids (RLs) and alkylbenzene sulfonate (ABS) in a 1:1 mass ratio is determined to be the optimal mixed surfactant and labeled RL/ABS-opt. Second, the interfacial activities, phase behaviors, and wettability alteration capabilities of ASP solutions with RL/ABS-opt are studied. Then, 1.0 wt% NaOH and 0.2 wt% RL/ABS-opt are determined to construct a new ASP system. Subsequently, the waterflooded cores are displaced using the new and the classical ASP systems. Based on the promising experimental results, the new ASP system floods a test block of 56 wells for 3 years. The EOR and surfactant costs are calculated to determine the technical and economic effects. Finally, the concentrations of surfactants before and after activated sludge treatment (AST) are tested by spectrophotometry to verify the biodegradability of RLs better than that of ABS. The laboratory and field results indicate that more biosurfactants and fewer synthetic surfactants could improve ASP flooding to be more environmentally friendly and cost-effective with a higher EOR.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"68 17","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141276527","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}
Methane emissions at seafloor are generally associated with the upward methane migration from the deeper sediments, partly from hydrate dissociation. The anaerobic oxidation of methane (AOM) occurring in the surface sediments acts as an important barrier to methane emissions, caused by the reaction between sulfate ions and dissolved methane molecules. However, the current hydrate simulators rarely consider the transport of sulfate and the subsequent AOM reaction. In this study, to investigate AOM effects in hydrate systems, a new simulator named Tough+Hydrate+AOM (THA) is developed by combining the reaction transport model (RTM) with the widely used Tough+Hydrate (T+H) simulator. The THA simulator is validated using the single-phase cases of the Dvurechenskii mud volcano in Black Sea since the results obtained are in good agreement with previous ones. This simulator is then applied to investigate the response of a hydrate reservoir offshore West Svalbard to seasonal seafloor temperature change and also to confirm its adaptability in multiphase hydrate systems. The results obtained suggest that the AOM filter efficiency is as low as 5%, meaning that the majority of methane released from hydrate dissociation in the deeper sediments will escape into the ocean. The THA simulator considering AOM is expected to be an important tool for assessing methane emissions caused by hydrate destabilization.
{"title":"A Simulator Based on Coupling of Reaction Transport Model and Multiphase Hydrate Simulator and Its Application to Studies of Methane Transportation in Marine Sediments","authors":"Haotian Liu, Jiecheng Zhang, Hailong Lu","doi":"10.2118/221456-pa","DOIUrl":"https://doi.org/10.2118/221456-pa","url":null,"abstract":"\u0000 Methane emissions at seafloor are generally associated with the upward methane migration from the deeper sediments, partly from hydrate dissociation. The anaerobic oxidation of methane (AOM) occurring in the surface sediments acts as an important barrier to methane emissions, caused by the reaction between sulfate ions and dissolved methane molecules. However, the current hydrate simulators rarely consider the transport of sulfate and the subsequent AOM reaction. In this study, to investigate AOM effects in hydrate systems, a new simulator named Tough+Hydrate+AOM (THA) is developed by combining the reaction transport model (RTM) with the widely used Tough+Hydrate (T+H) simulator. The THA simulator is validated using the single-phase cases of the Dvurechenskii mud volcano in Black Sea since the results obtained are in good agreement with previous ones. This simulator is then applied to investigate the response of a hydrate reservoir offshore West Svalbard to seasonal seafloor temperature change and also to confirm its adaptability in multiphase hydrate systems. The results obtained suggest that the AOM filter efficiency is as low as 5%, meaning that the majority of methane released from hydrate dissociation in the deeper sediments will escape into the ocean. The THA simulator considering AOM is expected to be an important tool for assessing methane emissions caused by hydrate destabilization.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"5 8","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141274596","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 objective of this study is to evaluate facies heterogeneity, including both lateral and vertical distributions within the mixed carbonate and siliciclastic reservoirs of the Mississippian System (Lower Carboniferous). This research and statistical approach will aid in future investigations related to determining optimal landing zones, enhancing completion designs, and providing geologic insight into fracture driven well interference studies to increase production efficiency. This study integrates well log, petrographic, sedimentologic, and conventional core analyses along a set of transects across the Anadarko Basin and includes the development of core-based facies logs. Statistical analysis indicates that the Mississippian System in the STACK play of the Anadarko Basin is fundamentally a highly layered rhythmic succession in which a variety of carbonate rock types, siliciclastic rock types, and chert tend to form couplets with siltstone. Thickness-frequency distributions and Markov chain analysis indicate that sediment thickness and lithologic transitions were stochastically regulated and that lithologic cyclicity is not apparent. Overall lithologic trends indicate a transition from carbonate to sandstone in the midramp and from carbonate to mudstone and siltstone in the outer ramp. Stratal geometry defines a series of south-prograding clinoforms, and detailed analysis of vertical trends in the distribution of mudstone, siltstone, sandstone, chert, and carbonate facilitates identification of shoaling-upward parasequences that can be correlated regionally.
{"title":"Mississippian (Lower Carboniferous) Facies Heterogeneity and Distribution within the Mixed Carbonate-Siliciclastic Reservoirs of the Midcontinent STACK Play, Oklahoma, USA","authors":"Jamar Bynum, Jack Pashin, C. Wethington","doi":"10.2118/221455-pa","DOIUrl":"https://doi.org/10.2118/221455-pa","url":null,"abstract":"\u0000 The objective of this study is to evaluate facies heterogeneity, including both lateral and vertical distributions within the mixed carbonate and siliciclastic reservoirs of the Mississippian System (Lower Carboniferous). This research and statistical approach will aid in future investigations related to determining optimal landing zones, enhancing completion designs, and providing geologic insight into fracture driven well interference studies to increase production efficiency. This study integrates well log, petrographic, sedimentologic, and conventional core analyses along a set of transects across the Anadarko Basin and includes the development of core-based facies logs. Statistical analysis indicates that the Mississippian System in the STACK play of the Anadarko Basin is fundamentally a highly layered rhythmic succession in which a variety of carbonate rock types, siliciclastic rock types, and chert tend to form couplets with siltstone. Thickness-frequency distributions and Markov chain analysis indicate that sediment thickness and lithologic transitions were stochastically regulated and that lithologic cyclicity is not apparent. Overall lithologic trends indicate a transition from carbonate to sandstone in the midramp and from carbonate to mudstone and siltstone in the outer ramp. Stratal geometry defines a series of south-prograding clinoforms, and detailed analysis of vertical trends in the distribution of mudstone, siltstone, sandstone, chert, and carbonate facilitates identification of shoaling-upward parasequences that can be correlated regionally.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141277482","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}
Lu Yang, Kai Zhang, Huaqing Zhang, Limin Zhang, Jun Yao, Yang Wang, Yongfei Yang, Jian Wang
The prediction of oil production following enhancement techniques has garnered widespread attention, leading scientists to explore this area using machine learning. However, field data collection constraints and single model accuracy limitations mean few models can precisely predict daily oil production after technique implementation. Building upon previous research, this paper introduces a model that predicts oil production after enhancement operations, utilizing multidimensional feature representation learning. It thoroughly examines three characteristic categories affecting the effectiveness of oil production enhancement techniques: geological static parameters, production dynamic parameters, and enhancement technique process parameters. The model comprehensively explores these features with an emphasis on global spatial, local spatial, and temporal information. A complete machine learning prediction process is established, which includes data preprocessing, model training, cross-validation, and oil production prediction after implementing enhancement techniques. The first part of the model involves representation learning on processed data, producing three sets of new features: global spatial, local spatial, and temporal information. These features are fused with the original data, serving as input for the advanced ensemble learning model XGBoost, which predicts daily oil production after implementing the technique. Following the construction of the model, actual field data from profile control techniques are selected to conduct various evaluations based on the model’s performance on validation and test sets. Compared with traditional machine learning regression algorithms, this model demonstrates significantly higher predictive accuracy. The prediction accuracy for oil production using given enhanced techniques reached 96% in the validation set and 94% in the test set. This research provides a technical foundation for selecting appropriate production enhancement techniques in oil fields by accurately predicting oil production after implementing enhancement techniques, which offers guidance for actual oilfield production.
{"title":"Predicting Oil Production After Enhancement Techniques Using Multidimensional Feature Representation Learning: A Case Study of Profile Control Technique","authors":"Lu Yang, Kai Zhang, Huaqing Zhang, Limin Zhang, Jun Yao, Yang Wang, Yongfei Yang, Jian Wang","doi":"10.2118/221461-pa","DOIUrl":"https://doi.org/10.2118/221461-pa","url":null,"abstract":"\u0000 The prediction of oil production following enhancement techniques has garnered widespread attention, leading scientists to explore this area using machine learning. However, field data collection constraints and single model accuracy limitations mean few models can precisely predict daily oil production after technique implementation. Building upon previous research, this paper introduces a model that predicts oil production after enhancement operations, utilizing multidimensional feature representation learning. It thoroughly examines three characteristic categories affecting the effectiveness of oil production enhancement techniques: geological static parameters, production dynamic parameters, and enhancement technique process parameters. The model comprehensively explores these features with an emphasis on global spatial, local spatial, and temporal information. A complete machine learning prediction process is established, which includes data preprocessing, model training, cross-validation, and oil production prediction after implementing enhancement techniques. The first part of the model involves representation learning on processed data, producing three sets of new features: global spatial, local spatial, and temporal information. These features are fused with the original data, serving as input for the advanced ensemble learning model XGBoost, which predicts daily oil production after implementing the technique. Following the construction of the model, actual field data from profile control techniques are selected to conduct various evaluations based on the model’s performance on validation and test sets. Compared with traditional machine learning regression algorithms, this model demonstrates significantly higher predictive accuracy. The prediction accuracy for oil production using given enhanced techniques reached 96% in the validation set and 94% in the test set. This research provides a technical foundation for selecting appropriate production enhancement techniques in oil fields by accurately predicting oil production after implementing enhancement techniques, which offers guidance for actual oilfield production.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"136 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141406151","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}
Sulfate-reducing microorganisms are found in various environments, such as shallow marine and freshwater sediments, groundwater, hydrocarbon reservoirs, hydrothermal vents, and mud volcanoes. The reduction of sulfate to hydrogen sulfide (H2S) by sulfate-reducing microorganisms, usually during and after flooding oil reservoirs with seawater (SW), is known as microbial reservoir souring. H2S is a hazardous and corrosive gas, which increases the treatment costs of the produced fluids. Other than the microbiological aspect of this phenomenon, the interplay among the physical aspects of the multiphase flow and (bio)chemical reactions at various scales in the porous media of the subsurface can significantly contribute to the complexity of the problem. This study investigates real field data of several wells in an oil field in the Danish North Sea and presents a modified reservoir souring model coupled with a full-field reservoir model. The effect of various parameters on the production composition data is investigated, and, under various sets of assumptions, the model is matched against the history of the production data. The results demonstrate that sulfate concentration data in the produced water can be a useful compliment to the more common H2S concentration data in the produced gas when tuning the model, thus predicting the future of souring in the field. Moreover, it is shown that the production data can be used to infer the activity of various microbial communities in different locations of the reservoir. Interestingly, the data suggest that the change in the near-wellbore environment during drilling and the completion or the production wells may activate or introduce strains of sulfate-reducing microorganisms, which are responsible for the increase in H2S content in the produced gas during the early stages of production. Microbial souring in the waterflooded regions, on the other hand, corresponds to the increase in H2S production in the later stages of production. Furthermore, it is shown how different sectors of the same field show different souring behaviors and macroscale growth rates (GRs), which are attributed to different elements that affect flow patterns, such as the presence of darcy-scale heterogeneity and fractures.
{"title":"Microbial Sulfate Reduction in Underground Reservoirs: Learnings from Full-Field Modeling and Field Data","authors":"Ali Mahmoodi, Hamidreza M. Nick","doi":"10.2118/221453-pa","DOIUrl":"https://doi.org/10.2118/221453-pa","url":null,"abstract":"\u0000 Sulfate-reducing microorganisms are found in various environments, such as shallow marine and freshwater sediments, groundwater, hydrocarbon reservoirs, hydrothermal vents, and mud volcanoes. The reduction of sulfate to hydrogen sulfide (H2S) by sulfate-reducing microorganisms, usually during and after flooding oil reservoirs with seawater (SW), is known as microbial reservoir souring. H2S is a hazardous and corrosive gas, which increases the treatment costs of the produced fluids. Other than the microbiological aspect of this phenomenon, the interplay among the physical aspects of the multiphase flow and (bio)chemical reactions at various scales in the porous media of the subsurface can significantly contribute to the complexity of the problem. This study investigates real field data of several wells in an oil field in the Danish North Sea and presents a modified reservoir souring model coupled with a full-field reservoir model. The effect of various parameters on the production composition data is investigated, and, under various sets of assumptions, the model is matched against the history of the production data. The results demonstrate that sulfate concentration data in the produced water can be a useful compliment to the more common H2S concentration data in the produced gas when tuning the model, thus predicting the future of souring in the field. Moreover, it is shown that the production data can be used to infer the activity of various microbial communities in different locations of the reservoir. Interestingly, the data suggest that the change in the near-wellbore environment during drilling and the completion or the production wells may activate or introduce strains of sulfate-reducing microorganisms, which are responsible for the increase in H2S content in the produced gas during the early stages of production. Microbial souring in the waterflooded regions, on the other hand, corresponds to the increase in H2S production in the later stages of production. Furthermore, it is shown how different sectors of the same field show different souring behaviors and macroscale growth rates (GRs), which are attributed to different elements that affect flow patterns, such as the presence of darcy-scale heterogeneity and fractures.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"2 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141396131","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}
Bo Ren, James Littlefield, Cunqi Jia, Hailun Ni, Ian Duncan
Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale. Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin. We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one. We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.
{"title":"Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Heterogeneity Trapping of CO2 in Storage Aquifers","authors":"Bo Ren, James Littlefield, Cunqi Jia, Hailun Ni, Ian Duncan","doi":"10.2118/214925-pa","DOIUrl":"https://doi.org/10.2118/214925-pa","url":null,"abstract":"\u0000 Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale.\u0000 Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin.\u0000 We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one.\u0000 We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"142 13","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141281225","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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