P. E. Aranha, L. G. O. Lopes, E. S. Paranhos Sobrinho, I. M. N. Oliveira, J. P. N. de Araújo, B. B. Santos, E. T. Lima Junior, T. B. da Silva, T. M. A. Vieira, W. W. M. Lira, N. A. Policarpo, M. A. Sampaio
Summary Detecting unexpected events is a field of interest in oil and gas companies to improve operational safety and reduce costs associated with nonproductive time (NPT) and failure repair. This work presents a system for real-time monitoring of unwanted events using the production sensor data from oil wells. It uses a combination of long short-term memory (LSTM) autoencoder and a rule-based analytic approach to perform the detection of anomalies from sensor data. Initial studies are conducted to determine the behavior and correlations of pressure and temperature values for the most common combinations of well valve states. The proposed methodology uses pressure and temperature sensor data, from which a decision diagram (DD) classifies the well status, and this response is applied to the training of neural networks devoted to anomaly detection. Data sets related to several operations in wells located at different oil fields are used to train and validate the dual approach presented. The combination of the two techniques enables the deep neural network to evolve constantly through the normal data collected by the analytical method. The developed system exhibits high accuracy, with true positive detection rates exceeding 90% in the early stages of anomalies identified in both simulated and actual well production scenarios. It was implemented in more than 20 floating production, storage, and offloading (FPSO) vessels, monitoring more than 250 production/injection subsea wells, and can be applied both in real-time operation and in testing scenarios.
{"title":"A System to Detect Oilwell Anomalies Using Deep Learning and Decision Diagram Dual Approach","authors":"P. E. Aranha, L. G. O. Lopes, E. S. Paranhos Sobrinho, I. M. N. Oliveira, J. P. N. de Araújo, B. B. Santos, E. T. Lima Junior, T. B. da Silva, T. M. A. Vieira, W. W. M. Lira, N. A. Policarpo, M. A. Sampaio","doi":"10.2118/218017-pa","DOIUrl":"https://doi.org/10.2118/218017-pa","url":null,"abstract":"Summary Detecting unexpected events is a field of interest in oil and gas companies to improve operational safety and reduce costs associated with nonproductive time (NPT) and failure repair. This work presents a system for real-time monitoring of unwanted events using the production sensor data from oil wells. It uses a combination of long short-term memory (LSTM) autoencoder and a rule-based analytic approach to perform the detection of anomalies from sensor data. Initial studies are conducted to determine the behavior and correlations of pressure and temperature values for the most common combinations of well valve states. The proposed methodology uses pressure and temperature sensor data, from which a decision diagram (DD) classifies the well status, and this response is applied to the training of neural networks devoted to anomaly detection. Data sets related to several operations in wells located at different oil fields are used to train and validate the dual approach presented. The combination of the two techniques enables the deep neural network to evolve constantly through the normal data collected by the analytical method. The developed system exhibits high accuracy, with true positive detection rates exceeding 90% in the early stages of anomalies identified in both simulated and actual well production scenarios. It was implemented in more than 20 floating production, storage, and offloading (FPSO) vessels, monitoring more than 250 production/injection subsea wells, and can be applied both in real-time operation and in testing scenarios.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135456015","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}
Niklas Geissler, Florian Garsche, Vitalii Samus, Berker Polat, Francesca Di Mare, Rolf Bracke
Summary Exploration risks of geothermal projects are high, as required economic production rates are often not achieved. Stimulation methods from the oil and gas industry, such as radial jet drilling (RJD), which can be used to cost-effectively create flow paths around a main borehole, are usually not applicable in geothermal applications due to especially hard reservoir formations. Because of that, a novel technology called micro-turbine drilling (MTD®) has been developed, which allows for the drilling of micro-sidetracks from cased boreholes even into very hard reservoir rock. The approach is based on the principles of the RJD operation. However, instead of a jetting nozzle, a microdrilling turbine is used to drive a bit that mechanically drills rock. This study presents the results of the proof of concept for MTD, which was conducted in the BedrettoLab in Switzerland at a depth of up to 1,053 ft (321 m) in granite rock.
{"title":"Proof of Concept in a Full-Scale Field Test for the Novel Micro-Turbine Drilling Technology from a Cased Borehole in Granite Rock","authors":"Niklas Geissler, Florian Garsche, Vitalii Samus, Berker Polat, Francesca Di Mare, Rolf Bracke","doi":"10.2118/218378-pa","DOIUrl":"https://doi.org/10.2118/218378-pa","url":null,"abstract":"Summary Exploration risks of geothermal projects are high, as required economic production rates are often not achieved. Stimulation methods from the oil and gas industry, such as radial jet drilling (RJD), which can be used to cost-effectively create flow paths around a main borehole, are usually not applicable in geothermal applications due to especially hard reservoir formations. Because of that, a novel technology called micro-turbine drilling (MTD®) has been developed, which allows for the drilling of micro-sidetracks from cased boreholes even into very hard reservoir rock. The approach is based on the principles of the RJD operation. However, instead of a jetting nozzle, a microdrilling turbine is used to drive a bit that mechanically drills rock. This study presents the results of the proof of concept for MTD, which was conducted in the BedrettoLab in Switzerland at a depth of up to 1,053 ft (321 m) in granite rock.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"50 8","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135615523","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}
Fiber materials have become an attractive choice for lost circulation material (LCM) applications recently. While there has been significant attention on the size, aspect ratio, and size distribution of fibers, the stiffness or basically the effect of their deformability on the sealing capability has not been studied rigorously. Experimental evaluations of fibers with different material properties could be a cumbersome, time-consuming, and expensive process. Most laboratory studies are limited to one or just a few different types of materials. Hence, a novel two-way-coupled computational fluid dynamics and discrete element method (CFD-DEM)-based numerical model is used to overcome this limitation and to simulate motion, collision, deformation, and finally entanglement of individual LCM fibers moving with the fluid along a fracture. Fiber stiffness is determined by the Young’s modulus, the fiber diameter, and the fiber length. Therefore, we investigate this effect in a parametric study with a focus on the impact of the length, diameter, and Young’s modulus of the fiber on their sealing capability. An in-depth analysis reveals that the bridging mechanism for fiber LCM changes with the stiffness of the fiber. Two distinct bridging mechanisms dependent on the fiber stiffness for fiber LCMs are identified. Based on the simulation results, we developed a conceptual model for the different mechanisms that fibers use for bridge initiation. It is also observed that in determining LCM effectiveness, both the fiber stiffness and the fiber dimensions go hand in hand. Stiff fibers were associated with greater maximum plugging pressures (MPPs). The effect of using a mix of soft and stiff fibers on fracture plugging effectiveness has been evaluated. The fiber LCM effectiveness as a consequence of the bending stiffness on bridging larger fractures is also investigated. lost circulation materials, fibers, fracture sealing, bridging mechanism
{"title":"Fiber Stiffness: An Essential Parameter of the Effectiveness of Fiber-Based Lost Circulation Materials—A CFD-DEM Numerical Investigation","authors":"Cassian Henriques, A. Dahi Taleghani","doi":"10.2118/218377-pa","DOIUrl":"https://doi.org/10.2118/218377-pa","url":null,"abstract":"Fiber materials have become an attractive choice for lost circulation material (LCM) applications recently. While there has been significant attention on the size, aspect ratio, and size distribution of fibers, the stiffness or basically the effect of their deformability on the sealing capability has not been studied rigorously. Experimental evaluations of fibers with different material properties could be a cumbersome, time-consuming, and expensive process. Most laboratory studies are limited to one or just a few different types of materials. Hence, a novel two-way-coupled computational fluid dynamics and discrete element method (CFD-DEM)-based numerical model is used to overcome this limitation and to simulate motion, collision, deformation, and finally entanglement of individual LCM fibers moving with the fluid along a fracture. Fiber stiffness is determined by the Young’s modulus, the fiber diameter, and the fiber length. Therefore, we investigate this effect in a parametric study with a focus on the impact of the length, diameter, and Young’s modulus of the fiber on their sealing capability. An in-depth analysis reveals that the bridging mechanism for fiber LCM changes with the stiffness of the fiber. Two distinct bridging mechanisms dependent on the fiber stiffness for fiber LCMs are identified. Based on the simulation results, we developed a conceptual model for the different mechanisms that fibers use for bridge initiation. It is also observed that in determining LCM effectiveness, both the fiber stiffness and the fiber dimensions go hand in hand. Stiff fibers were associated with greater maximum plugging pressures (MPPs). The effect of using a mix of soft and stiff fibers on fracture plugging effectiveness has been evaluated. The fiber LCM effectiveness as a consequence of the bending stiffness on bridging larger fractures is also investigated. lost circulation materials, fibers, fracture sealing, bridging mechanism","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"4 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139303701","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}
Umar Alfazazi, Nithin Chacko Thomas, Emad Walid Al-Shalabi, Waleed AlAmeri
Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.
{"title":"Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions","authors":"Umar Alfazazi, Nithin Chacko Thomas, Emad Walid Al-Shalabi, Waleed AlAmeri","doi":"10.2118/207892-pa","DOIUrl":"https://doi.org/10.2118/207892-pa","url":null,"abstract":"Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"84 11","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135270651","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}
Olwijn Leeuwenburgh, Paul J. P. Egberts, Eduardo G. D. Barros, Lukasz P. Turchan, Fahad Dilib, Ole-Petter Lødøen, Wouter J. de Bruin
Summary Model-based reservoir management workflows rely on the ability to generate predictions for large numbers of model and decision scenarios. When suitable simulators or models are not available or cannot be evaluated in a sufficiently short time frame, surrogate modeling techniques can be used instead. In the first part of this paper, we describe extensions of a recently developed open-source framework for creating and training flow network surrogate models, called FlowNet. In particular, we discuss functionality to reproduce historical well rates for wells with arbitrary trajectories, multiple perforated sections, and changing well type or injection phase, as one may encounter in large and complex fields with a long history. Furthermore, we discuss strategies for the placement of additional network nodes in the presence of flow barriers. Despite their flexibility and speed, the applicability of flow network models is limited to phenomena that can be simulated with available numerical simulators. Prediction of poorly understood physics, such as reservoir souring, may require a more data-driven approach. We discuss an extension of the FlowNet framework with a machine learning (ML) proxy for the purpose of generating predictions of H2S production rates. The combined data-physics proxy is trained on historical liquid volume rates, seawater fractions, and H2S production data from a real North Sea oil and gas field, and is then used to generate predictions of H2S production. Several experiments are presented in which the data source, data type, and length of the history are varied. Results indicate that, given a sufficient number of training data, FlowNet is able to produce reliable predictions of conventional oilfield quantities. An experiment performed with the ML proxy suggests that, at least for some production wells, useful predictions of H2S production can be obtained much faster and at much lower computational cost and complexity than would be possible with high-fidelity models. Finally, we discuss some of the current limitations of the approach and options to address them.
{"title":"A Hybrid Data-Physics Framework for Reservoir Performance Prediction with Application to H2S Production","authors":"Olwijn Leeuwenburgh, Paul J. P. Egberts, Eduardo G. D. Barros, Lukasz P. Turchan, Fahad Dilib, Ole-Petter Lødøen, Wouter J. de Bruin","doi":"10.2118/218000-pa","DOIUrl":"https://doi.org/10.2118/218000-pa","url":null,"abstract":"Summary Model-based reservoir management workflows rely on the ability to generate predictions for large numbers of model and decision scenarios. When suitable simulators or models are not available or cannot be evaluated in a sufficiently short time frame, surrogate modeling techniques can be used instead. In the first part of this paper, we describe extensions of a recently developed open-source framework for creating and training flow network surrogate models, called FlowNet. In particular, we discuss functionality to reproduce historical well rates for wells with arbitrary trajectories, multiple perforated sections, and changing well type or injection phase, as one may encounter in large and complex fields with a long history. Furthermore, we discuss strategies for the placement of additional network nodes in the presence of flow barriers. Despite their flexibility and speed, the applicability of flow network models is limited to phenomena that can be simulated with available numerical simulators. Prediction of poorly understood physics, such as reservoir souring, may require a more data-driven approach. We discuss an extension of the FlowNet framework with a machine learning (ML) proxy for the purpose of generating predictions of H2S production rates. The combined data-physics proxy is trained on historical liquid volume rates, seawater fractions, and H2S production data from a real North Sea oil and gas field, and is then used to generate predictions of H2S production. Several experiments are presented in which the data source, data type, and length of the history are varied. Results indicate that, given a sufficient number of training data, FlowNet is able to produce reliable predictions of conventional oilfield quantities. An experiment performed with the ML proxy suggests that, at least for some production wells, useful predictions of H2S production can be obtained much faster and at much lower computational cost and complexity than would be possible with high-fidelity models. Finally, we discuss some of the current limitations of the approach and options to address them.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"8 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":"135371875","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 To investigate the wax precipitation mechanism of condensate in a wellbore during the ultradeep gas condensate reservoir development, condensate samples were prepared in this work. Changes in the temperature and pressure of fluid flow in the wellbore are simulated by a high-temperature and high-pressure pressure/volume/temperature (PVT) system. This simulation explores their influences on the wax precipitation of the condensate produced from the target reservoir. The results show that the temperature decrease weakens the wax molecular movement activity and promotes the precipitation of wax, resulting in the expansion of the pressure range in which wax precipitation occurs in the system. Meanwhile, decreasing the pressure promotes wax aggregation by increasing van der Waals forces between wax molecules, thereby increasing the wax precipitation rate. At different temperatures, the wax precipitate amount first increases and then decreases with decreasing pressure, which is determined by the wax solubility and remaining content in the system. Since the solubility of a low carbon number component is more sensitive to temperature and pressure changes than that of a high carbon number component, in the early stages of experimental temperature and pressure decreases, the precipitation of coarse crystalline wax with carbon numbers ranging from C16 to C30 is more active than that of microcrystalline wax with carbon numbers exceeding C30. The remaining amount of the former component in the system decreases rapidly, and its precipitation capacity weakens, thus increasing the amount of the latter component in the precipitated wax during the later stage of experiments; this trend corresponds to the shift of the curve peak of the wax carbon number distribution to an abscissa interval with the relatively high carbon numbers. This work can provide reference data for the prediction of the well depth at which the wax precipitation occurs and the wax composition, aiming to promote the implementation of wellbore wax blockage prevention programs.
{"title":"Effect of Pressure and Temperature Variation on Wax Precipitation in the Wellbore of Ultradeep Gas Condensate Reservoirs","authors":"Chao Zhang, Zihan Gu, Lihu Cao, Hongjun Wu, Jiquan Liu, Pengfei Li, Dexin Zhang, Zhaomin Li","doi":"10.2118/218373-pa","DOIUrl":"https://doi.org/10.2118/218373-pa","url":null,"abstract":"Summary To investigate the wax precipitation mechanism of condensate in a wellbore during the ultradeep gas condensate reservoir development, condensate samples were prepared in this work. Changes in the temperature and pressure of fluid flow in the wellbore are simulated by a high-temperature and high-pressure pressure/volume/temperature (PVT) system. This simulation explores their influences on the wax precipitation of the condensate produced from the target reservoir. The results show that the temperature decrease weakens the wax molecular movement activity and promotes the precipitation of wax, resulting in the expansion of the pressure range in which wax precipitation occurs in the system. Meanwhile, decreasing the pressure promotes wax aggregation by increasing van der Waals forces between wax molecules, thereby increasing the wax precipitation rate. At different temperatures, the wax precipitate amount first increases and then decreases with decreasing pressure, which is determined by the wax solubility and remaining content in the system. Since the solubility of a low carbon number component is more sensitive to temperature and pressure changes than that of a high carbon number component, in the early stages of experimental temperature and pressure decreases, the precipitation of coarse crystalline wax with carbon numbers ranging from C16 to C30 is more active than that of microcrystalline wax with carbon numbers exceeding C30. The remaining amount of the former component in the system decreases rapidly, and its precipitation capacity weakens, thus increasing the amount of the latter component in the precipitated wax during the later stage of experiments; this trend corresponds to the shift of the curve peak of the wax carbon number distribution to an abscissa interval with the relatively high carbon numbers. This work can provide reference data for the prediction of the well depth at which the wax precipitation occurs and the wax composition, aiming to promote the implementation of wellbore wax blockage prevention programs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"40 12","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135455133","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 thorough understanding of fluid transport in ultratight shale reservoirs is crucial for designing and optimizing cyclic solvent injection processes, known as huff ’n’ puff (HnP). We develop a two-phase multicomponent numerical model to investigate hydrocarbon and solvent transport and species mixing during HnP. Unlike the conventional modeling approaches that rely on bulk fluid (advective) transport frameworks, the proposed model considers species transport within nanopores. The chemical potential gradient is considered the driving force for the movement of nonideal fluid mixtures. A binary friction concept is adopted that considers friction between different fluid molecules and between fluid molecules and pore walls. After validating the developed model against analytical solutions and experimental data, the model examines solvent HnP enhanced oil recovery (EOR) mechanisms by considering four-component oil and Eagle Ford crude oil systems. The impacts of injection pressure, primary production duration, soaking time, and solvent type on the oil recovery are examined. The results reveal that the formation of a solvent-oil mixing zone during the huff period and oil swelling and vaporization of oil components during the puff period are key mechanisms for enhancing oil recovery. Furthermore, the incremental recovery factor (RF) increases with injection pressure, even when the injection pressure exceeds the minimum miscibility pressure (MMP), implying that MMP may not play a critical role in the design of HnP in ultratight reservoirs. The results suggest that injecting solvents after a sufficient primary production period is more effective, allowing reservoir pressure depletion. Injecting the solvent without enough primary production may result in significant production of the injected solvent. The results show that the solvent-oil mixing zone expands, and the solvent recycling ratio decreases as soaking time increases. However, short soaking periods with higher HnP cycles are recommended for improving oil recovery at a given time frame. Finally, CO2 HnP outperforms CH4 or N2 HnP due to the higher ability of CO2 to extract a larger amount of intermediate and heavy components into the vapor phase, which has higher transmissibilities as compared with the liquid phase.
{"title":"Multiphase Multicomponent Transport Modeling of Cyclic Solvent Injection in Shale Reservoirs","authors":"Ming Ma, Hamid Emami‐Meybodi","doi":"10.2118/210480-pa","DOIUrl":"https://doi.org/10.2118/210480-pa","url":null,"abstract":"A thorough understanding of fluid transport in ultratight shale reservoirs is crucial for designing and optimizing cyclic solvent injection processes, known as huff ’n’ puff (HnP). We develop a two-phase multicomponent numerical model to investigate hydrocarbon and solvent transport and species mixing during HnP. Unlike the conventional modeling approaches that rely on bulk fluid (advective) transport frameworks, the proposed model considers species transport within nanopores. The chemical potential gradient is considered the driving force for the movement of nonideal fluid mixtures. A binary friction concept is adopted that considers friction between different fluid molecules and between fluid molecules and pore walls. After validating the developed model against analytical solutions and experimental data, the model examines solvent HnP enhanced oil recovery (EOR) mechanisms by considering four-component oil and Eagle Ford crude oil systems. The impacts of injection pressure, primary production duration, soaking time, and solvent type on the oil recovery are examined. The results reveal that the formation of a solvent-oil mixing zone during the huff period and oil swelling and vaporization of oil components during the puff period are key mechanisms for enhancing oil recovery. Furthermore, the incremental recovery factor (RF) increases with injection pressure, even when the injection pressure exceeds the minimum miscibility pressure (MMP), implying that MMP may not play a critical role in the design of HnP in ultratight reservoirs. The results suggest that injecting solvents after a sufficient primary production period is more effective, allowing reservoir pressure depletion. Injecting the solvent without enough primary production may result in significant production of the injected solvent. The results show that the solvent-oil mixing zone expands, and the solvent recycling ratio decreases as soaking time increases. However, short soaking periods with higher HnP cycles are recommended for improving oil recovery at a given time frame. Finally, CO2 HnP outperforms CH4 or N2 HnP due to the higher ability of CO2 to extract a larger amount of intermediate and heavy components into the vapor phase, which has higher transmissibilities as compared with the liquid phase.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"4 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139297551","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}
Hang Xu, Fujian Zhou, Hao Wu, Sasa Yang, Yuan Li, Yang Wang, Hao Bai, Erdong Yao, Hualei Xu
Hydraulic fracturing is an effective stimulation method to establish high-conductivity channels in tight reservoirs, and the effectiveness of man-made fractures largely depends on the proppant-carrying capacity of the fracturing fluids used. As a novel completion fluid, silica gel-based fracturing fluids have shown desirable stimulation effect in application cases, but a comprehensive evaluation of their proppant settling and transport behaviors in the laboratory remains lacking. In this paper, a silica gel-based fracturing fluid was prepared first, and then the rheological properties, including shear thinning, recovery behavior, and viscoelasticity of the fluid system, were measured. Afterward, the settling velocity of single-particle proppant and the settling rate of multiparticle proppant under various experimental conditions were investigated in the static fluid system; in addition, the dynamic proppant-carrying performance was evaluated using a visualized rough fracture model to study different factors on the dune distribution inside the fractures. Lastly, the proppant-carrying mechanism of silica gel-based fracturing fluid was revealed in three aspects. The rheological test result showed that the shear viscosity of silica gel-based fracturing fluid increased as the SiO2 concentration increased. Furthermore, all tested fluid samples exhibited an elastic modulus that is consistently greater than the viscous modulus, indicating that the silica gel-based fracturing fluid system has a dominant elastic response behavior. In the single-particle static settling test, there was a significant increase in the settling velocities as the particle diameter increased and as the temperature increased. Meanwhile, the settling rate of multiparticles showed a decreasing trend with the increase in mesh size, while the proppant settling rate gradually increased as the proppant concentration rose. The results of dynamic proppant-carrying experiments demonstrate that a higher pumping rate leads to an extended migration distance for proppant, resulting in formed sand dunes with reduced height within fractures. Conversely, an increase in proppant concentration and a reduction in mesh size tend to form higher sand dunes. The proppant-carrying mechanisms of the silica gel-based fracturing fluid relate to the self-polymerization and syneresis of silica gel, the noticeable elasticity characteristics, and the structural encapsulation effect formed between silica gel and proppant. A better understanding of the proppant settling and transport behaviors of silica gel-based fracturing fluid can be helpful in optimizing the hydraulic fracturing design and promoting field application.
{"title":"Experimental Research on the Proppant Settling and Transport Characteristics of Silica Gel-Based Fracturing Fluid","authors":"Hang Xu, Fujian Zhou, Hao Wu, Sasa Yang, Yuan Li, Yang Wang, Hao Bai, Erdong Yao, Hualei Xu","doi":"10.2118/218381-pa","DOIUrl":"https://doi.org/10.2118/218381-pa","url":null,"abstract":"Hydraulic fracturing is an effective stimulation method to establish high-conductivity channels in tight reservoirs, and the effectiveness of man-made fractures largely depends on the proppant-carrying capacity of the fracturing fluids used. As a novel completion fluid, silica gel-based fracturing fluids have shown desirable stimulation effect in application cases, but a comprehensive evaluation of their proppant settling and transport behaviors in the laboratory remains lacking. In this paper, a silica gel-based fracturing fluid was prepared first, and then the rheological properties, including shear thinning, recovery behavior, and viscoelasticity of the fluid system, were measured. Afterward, the settling velocity of single-particle proppant and the settling rate of multiparticle proppant under various experimental conditions were investigated in the static fluid system; in addition, the dynamic proppant-carrying performance was evaluated using a visualized rough fracture model to study different factors on the dune distribution inside the fractures. Lastly, the proppant-carrying mechanism of silica gel-based fracturing fluid was revealed in three aspects. The rheological test result showed that the shear viscosity of silica gel-based fracturing fluid increased as the SiO2 concentration increased. Furthermore, all tested fluid samples exhibited an elastic modulus that is consistently greater than the viscous modulus, indicating that the silica gel-based fracturing fluid system has a dominant elastic response behavior. In the single-particle static settling test, there was a significant increase in the settling velocities as the particle diameter increased and as the temperature increased. Meanwhile, the settling rate of multiparticles showed a decreasing trend with the increase in mesh size, while the proppant settling rate gradually increased as the proppant concentration rose. The results of dynamic proppant-carrying experiments demonstrate that a higher pumping rate leads to an extended migration distance for proppant, resulting in formed sand dunes with reduced height within fractures. Conversely, an increase in proppant concentration and a reduction in mesh size tend to form higher sand dunes. The proppant-carrying mechanisms of the silica gel-based fracturing fluid relate to the self-polymerization and syneresis of silica gel, the noticeable elasticity characteristics, and the structural encapsulation effect formed between silica gel and proppant. A better understanding of the proppant settling and transport behaviors of silica gel-based fracturing fluid can be helpful in optimizing the hydraulic fracturing design and promoting field application.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"2011 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139301381","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}
As the exploration of the South China Sea continues into deeper water, the chances of encountering nonhydrocarbon gas (CO2, N2, etc.) reservoirs rise. The question of how to avoid the risks associated with the discovery of nonhydrocarbon gas reservoirs becomes an issue for deepwater (DW) oil and gas exploration. Geomicrobial hydrocarbon detection (GMHD) is a nonseismic hydrocarbon detection technology that is able to predict the hydrocarbon potential of a prospective area at depth. This is accomplished via the detection of specific hydrocarbon-oxidizing bacteria in both onshore soils and offshore sea bottom sediment samples. The effectiveness of this method has been proved repeatedly in DW explorations of the northern South China Sea. It documents a possible solution to nonhydrocarbon gas risk prediction by combining the oil and gas prediction results of geomicrobial hydrocarbon detection with results from geological and geophysical studies to analyze the different microbial responses above nonhydrocarbon gas and hydrocarbon gas reservoirs. This was verified in the DW exploration practices undertaken in the Pearl River Mouth Basin and Qiongdongnan Basin of South China Sea.
{"title":"Novel Use of Microbial Hydrocarbon Detection Technology in Reducing the Risk of Nonhydrocarbon Exploration in Oil and Gas Exploration in the South China Sea","authors":"Ding Li","doi":"10.2118/218008-pa","DOIUrl":"https://doi.org/10.2118/218008-pa","url":null,"abstract":"As the exploration of the South China Sea continues into deeper water, the chances of encountering nonhydrocarbon gas (CO2, N2, etc.) reservoirs rise. The question of how to avoid the risks associated with the discovery of nonhydrocarbon gas reservoirs becomes an issue for deepwater (DW) oil and gas exploration. Geomicrobial hydrocarbon detection (GMHD) is a nonseismic hydrocarbon detection technology that is able to predict the hydrocarbon potential of a prospective area at depth. This is accomplished via the detection of specific hydrocarbon-oxidizing bacteria in both onshore soils and offshore sea bottom sediment samples. The effectiveness of this method has been proved repeatedly in DW explorations of the northern South China Sea. It documents a possible solution to nonhydrocarbon gas risk prediction by combining the oil and gas prediction results of geomicrobial hydrocarbon detection with results from geological and geophysical studies to analyze the different microbial responses above nonhydrocarbon gas and hydrocarbon gas reservoirs. This was verified in the DW exploration practices undertaken in the Pearl River Mouth Basin and Qiongdongnan Basin of South China Sea.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135371442","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}
Ronald W. P. Ortiz, Jessica Oliveira, Guilherme V. Vaz, Nayanna Souza Passos, Felipe J. S. Bispo, Vinicius Ottonio O. Gonçalves, Joao Cajaiba, Carlos A. Ortiz-Bravo, Vinicius Kartnaller
Summary Scale is a significant operational concern in petroleum production that is commonly addressed by using chemical inhibitors. However, commercial inhibitors can potentially be pollutants depending on their composition and method of disposal. Consequently, evaluating the potential of biodegradable molecules to inhibit scale has gained attention. This study evaluates the effect of a series of carbohydrates (i.e., glucose, fructose, sucrose, maltose, maltodextrin, and soluble starch) and the aqueous extract of potato pulp on calcium carbonate precipitation and scale formation. Precipitation tests were conducted by combining aqueous solutions of sodium bicarbonate (3000 mg L−1) and calcium chloride (4000 mg L−1) in the presence of each carbohydrate, the aqueous extract of potato pulp, or a commercial inhibitor (1000 mg L−1). The precipitation was monitored through RGB (red, green, and blue) image analysis and pH measurements. The induction time in the presence of glucose, fructose, maltose, and sucrose is two to three times longer than in the blank test (in the absence of an inhibitor). This effect is slightly more pronounced in the presence of maltodextrin and soluble starch (approximately four times longer). However, the drop in pH and the mass of solids recovered is similar for all the carbohydrates tested (~0.5 mg and 120 mg, respectively), suggesting that carbohydrates slightly influence the precipitation kinetics but do not affect the precipitation equilibrium. Scanning electron microscopy (SEM) and X-ray powder diffraction (XRD) analysis reveals that calcium carbonate precipitates as calcite and vaterite in the blank test. In the presence of glucose, fructose, maltose, and maltodextrin, calcium carbonate exclusively precipitates as calcite. However, in the presence of sucrose and soluble starch, calcium carbonate precipitates as both calcite and vaterite. Interestingly, a more prominent amount of vaterite was observed in the presence of soluble starch. All carbohydrates decrease the crystallite size of calcite, while sucrose and soluble starch increase the crystallite size of vaterite. The crystalline phases were also identified by Raman spectroscopy, ruling out the presence of any amorphous calcium carbonate phase. The inhibitory effect of soluble starch and the aqueous extract of potato pulp on calcium carbonate scale formation was evaluated in a dynamic scale loop (DSL) system. Soluble starch slightly delays scale formation even at high concentrations (1000 mg L−1). Conversely, the aqueous extract of potato pulp demonstrates enhanced performance by delaying scale formation by approximately 20 minutes for a 1-psi increase in the pressure of the tube and by more than 40 minutes for a 4-psi increase. As a result, it exhibited an impact on the kinetics of solid deposition. This agrees with the precipitation test in the presence of the potato extract (PE), which increases the induction time (from 2 minutes to 32 minutes), decreases the mas
结垢是石油生产中一个重要的操作问题，通常通过使用化学抑制剂来解决。然而，商业抑制剂可能是潜在的污染物，这取决于它们的组成和处理方法。因此，评估生物可降解分子抑制水垢的潜力已引起人们的关注。本研究评价了一系列碳水化合物(葡萄糖、果糖、蔗糖、麦芽糖、麦芽糊精和可溶性淀粉)和马铃薯浆水提物对碳酸钙沉淀和结垢的影响。沉淀试验采用碳酸氢钠水溶液(3000 mg L - 1)和氯化钙水溶液(4000 mg L - 1)混合的方法进行，同时存在每种碳水化合物、马铃薯浆水提取物或商业抑制剂(1000 mg L - 1)。通过RGB(红、绿、蓝)图像分析和pH测量来监测降水。在葡萄糖、果糖、麦芽糖和蔗糖的存在下，诱导时间比空白试验(不含抑制剂)的诱导时间长两到三倍。这种效果在麦芽糖糊精和可溶性淀粉存在时稍微明显一些(大约长四倍)。然而，对于所有测试的碳水化合物(分别为~0.5 mg和120 mg)， pH值下降和回收的固体质量相似，这表明碳水化合物轻微影响沉淀动力学，但不影响沉淀平衡。扫描电镜(SEM)和x射线粉末衍射(XRD)分析表明，在空白试验中碳酸钙以方解石和水晶石的形式析出。在葡萄糖、果糖、麦芽糖和麦芽糖糊精存在的情况下，碳酸钙只以方解石的形式析出。然而，在蔗糖和可溶性淀粉的存在下，碳酸钙沉淀为方解石和水晶石。有趣的是，在可溶性淀粉存在的情况下，观察到更多的水蛭。所有碳水化合物均使方解石的晶粒尺寸减小，而蔗糖和可溶性淀粉使方解石的晶粒尺寸增大。晶体相也被拉曼光谱鉴定，排除了任何无定形碳酸钙相的存在。在动态水垢循环(DSL)系统中，研究了可溶性淀粉和马铃薯浆水提物对碳酸钙水垢形成的抑制作用。可溶性淀粉即使在高浓度(1000 mg L−1)也会略微延迟水垢的形成。相反，马铃薯浆的水萃取物表现出增强的性能，当管内压力增加1 psi时，可以将结垢的形成延迟约20分钟，而当管内压力增加4 psi时，则可以将结垢的形成延迟40多分钟。结果表明，它对固体沉积动力学有影响。这与马铃薯提取物(PE)存在下的沉淀试验一致，PE增加了诱导时间(从2分钟增加到32分钟)，减少了固体质量(从116毫克减少到35毫克)，形成了更扭曲和更小的方解石颗粒。这些发现为利用淀粉类食品的水萃取物甚至淀粉类食品的废水开发绿色阻垢剂提供了一条有希望的途径。
{"title":"Evaluating the Potential of Biodegradable Carbohydrates and the Aqueous Extract of Potato Pulp to Inhibit Calcium Carbonate Scale in Petroleum Production","authors":"Ronald W. P. Ortiz, Jessica Oliveira, Guilherme V. Vaz, Nayanna Souza Passos, Felipe J. S. Bispo, Vinicius Ottonio O. Gonçalves, Joao Cajaiba, Carlos A. Ortiz-Bravo, Vinicius Kartnaller","doi":"10.2118/218011-pa","DOIUrl":"https://doi.org/10.2118/218011-pa","url":null,"abstract":"Summary Scale is a significant operational concern in petroleum production that is commonly addressed by using chemical inhibitors. However, commercial inhibitors can potentially be pollutants depending on their composition and method of disposal. Consequently, evaluating the potential of biodegradable molecules to inhibit scale has gained attention. This study evaluates the effect of a series of carbohydrates (i.e., glucose, fructose, sucrose, maltose, maltodextrin, and soluble starch) and the aqueous extract of potato pulp on calcium carbonate precipitation and scale formation. Precipitation tests were conducted by combining aqueous solutions of sodium bicarbonate (3000 mg L−1) and calcium chloride (4000 mg L−1) in the presence of each carbohydrate, the aqueous extract of potato pulp, or a commercial inhibitor (1000 mg L−1). The precipitation was monitored through RGB (red, green, and blue) image analysis and pH measurements. The induction time in the presence of glucose, fructose, maltose, and sucrose is two to three times longer than in the blank test (in the absence of an inhibitor). This effect is slightly more pronounced in the presence of maltodextrin and soluble starch (approximately four times longer). However, the drop in pH and the mass of solids recovered is similar for all the carbohydrates tested (~0.5 mg and 120 mg, respectively), suggesting that carbohydrates slightly influence the precipitation kinetics but do not affect the precipitation equilibrium. Scanning electron microscopy (SEM) and X-ray powder diffraction (XRD) analysis reveals that calcium carbonate precipitates as calcite and vaterite in the blank test. In the presence of glucose, fructose, maltose, and maltodextrin, calcium carbonate exclusively precipitates as calcite. However, in the presence of sucrose and soluble starch, calcium carbonate precipitates as both calcite and vaterite. Interestingly, a more prominent amount of vaterite was observed in the presence of soluble starch. All carbohydrates decrease the crystallite size of calcite, while sucrose and soluble starch increase the crystallite size of vaterite. The crystalline phases were also identified by Raman spectroscopy, ruling out the presence of any amorphous calcium carbonate phase. The inhibitory effect of soluble starch and the aqueous extract of potato pulp on calcium carbonate scale formation was evaluated in a dynamic scale loop (DSL) system. Soluble starch slightly delays scale formation even at high concentrations (1000 mg L−1). Conversely, the aqueous extract of potato pulp demonstrates enhanced performance by delaying scale formation by approximately 20 minutes for a 1-psi increase in the pressure of the tube and by more than 40 minutes for a 4-psi increase. As a result, it exhibited an impact on the kinetics of solid deposition. This agrees with the precipitation test in the presence of the potato extract (PE), which increases the induction time (from 2 minutes to 32 minutes), decreases the mas","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135565869","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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