Geoenergy Science and Engineering最新文献

{"title":"Annular cement sheath characterization and hydraulic aperture assessment through single- and two-phase seepage tests","authors":"Victor Nogueira Lima ,&nbsp;Amir Taheri ,&nbsp;Erlend Randeberg ,&nbsp;Hans Joakim Skadsem","doi":"10.1016/j.geoen.2024.213515","DOIUrl":"10.1016/j.geoen.2024.213515","url":null,"abstract":"<div><div>The integrity of well barriers is critical throughout the life cycle of oil and gas wells, with annular cement as a key component in maintaining the structural integrity of the barrier system. In this study, an annular cemented section with a well-defined microannulus was systematically constructed and characterized, and both single- and two-phase seepage tests were conducted to gain a deeper understanding of how relative permeability impacts the estimation of hydraulic aperture in potential leakage pathways. The test cell design allows modification of the microannulus gap size by changing the pressure applied inside the inner casing. This enables studying different microannulus sizes throughout the conducted tests. The single-phase seepage tests showed consistent measurements of hydraulic aperture for both gas and water, despite variations in fluid type and applied pressure, with surface roughness likely affecting the non-linear behavior of the hydraulic aperture under stress. The two-phase seepage tests demonstrated a clear relationship between breakthrough pressure and microannulus size, with the van Genuchten model providing a better fit for relative permeability and capillary pressure data. Breakthrough time experiments revealed that initial permeability estimations were significantly lower than those obtained from single-phase tests; however, once relative permeability at breakthrough was accounted for, the estimated absolute permeability values aligned closely with the single-phase experimental data. These findings offer valuable insights into the complex interactions between cement sheath integrity and gas migration, potentially contributing to developing new well integrity assessment technologies, including tracer gas below the well barrier element, as well as insights relevant for both gas migration and sustained casing pressure analysis.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213515"},"PeriodicalIF":0.0,"publicationDate":"2024-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142743721","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Controlling parameters of co-current and counter-current imbibition in naturally fractured reservoirs","authors":"Marzhan Karimova,&nbsp;Assylzhan Zhetpissov,&nbsp;Randy Hazlett,&nbsp;Peyman Pourafshary","doi":"10.1016/j.geoen.2024.213520","DOIUrl":"10.1016/j.geoen.2024.213520","url":null,"abstract":"<div><div>Naturally fractured formations are complex petroleum reservoirs that are poor candidates for waterflooding due to difficulties in controlling sweep. Injected water can readily propagate through the fracture system, bypassing the hydrocarbon stored in the matrix. Instead, such systems rely on spontaneous imbibition (SI) from the matrix into the extensive fracture gathering system. SI is a crucial recovery mechanism that relies on capillary pressure-dominated fluid movement. SI can occur through two modes, co-current (COSI) and counter-current (COUSI), depending on the relative direction of fluid movement in response to prevailing boundary conditions. Analytical solutions that incorporate the diffusivity coefficient, which combines relative permeability and capillary pressure curves, are used to describe co-current and counter-current imbibition mechanisms. The perturbation method is one approach in solving these analytical equations. In-situ water saturation profiles, ascertained through experimental CT scanning, serve as validation benchmarks for both co-current and counter-current models. The understanding of the SI process can give more details about the fracture-matrix interactions and the exchange function. Sensitivity studies with respect to the parameterization of the driving force for imbibition, capillary pressure, and the resistive forces, captured in relative permeability curves, can guide experimental study planning and aid in inverse problem analysis in the characterization of naturally fractured reservoirs. The results of a parametric study show that capillary pressure curve parameters, such as capillary entry pressure and capillary exponent, significantly affect the position of the waterfront which indicates the imbibition rate. In addition, the water relative permeability exponent has greater impact on both shape and position of water profile than other relative permeability parameters. The nonwetting phase parameters, like oil endpoint relative permeability and oil exponent, have the least influence on water saturation profile.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213520"},"PeriodicalIF":0.0,"publicationDate":"2024-11-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142721916","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}

{"title":"Flow Characteristics of Gas and Liquid in Pipeline Revealed by Machine Learning on Distributed Acoustic Sensing Data","authors":"Haochu Ku ,&nbsp;Kun-peng Zhang ,&nbsp;Xiang-ge He ,&nbsp;Min Zhang ,&nbsp;Hai-long Lu ,&nbsp;Yi Zhang ,&nbsp;Lin Cong","doi":"10.1016/j.geoen.2024.213518","DOIUrl":"10.1016/j.geoen.2024.213518","url":null,"abstract":"<div><div>The two-phase flow rates of gas and liquid in a pipeline are crucial parameters for optimizing gas-oil production strategies and ensuring the reliability of gas-oil transportation systems. Although available measurement techniques, such as various flow meters, offer accurate flow rate data, they might face limitations in providing distributed and real-time information at multiple points. Distributed Acoustic Sensing (DAS) offers a viable alternative for long-term, multipoint dynamic monitoring of the flow. However, the data acquired through fiber optic monitoring techniques are often difficult to analyze and process in real-time, while machine learning offers automatic identification of complex patterns and relationships within the data, enabling more precise predictions and classifications. To evaluate the feasibility of DAS technology combined with machine learning methods to estimate the gas-liquid flow rate in pipelines, an experimental loop that utilized DAS was developed to measure gas-liquid two-phase flow signals in pipelines. The machine learning method was then applied to analyze the DAS signals, based on which models were established to predict flow rates and regimes. Furthermore, validation experiments were conducted to assess the predictive performance of these models. Compared to the actual flow rates measured by electronic flowmeters, the results by integration of DAS and machine learning show the predictive accuracy of two models reach 97%. In the subsequent validation experiments, both the goodness of fit for the flow rate prediction model and accuracy for the flow regime prediction model exceeded 85%. Thus, compared to current flow measurement methods, the integration of DAS and machine learning not only provides accurate flow rate estimations but also offers available prediction of flow regimes, enhancing the measurement capabilities and technology insights.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213518"},"PeriodicalIF":0.0,"publicationDate":"2024-11-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142721921","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}

{"title":"Analytical procedure for tracing acrylamide and sulfonated co-polymers in groundwater affected by chemical enhanced oil recovery activities","authors":"Wannida Sapyen,&nbsp;Narong Praphairaksit,&nbsp;Apichat Imyim","doi":"10.1016/j.geoen.2024.213528","DOIUrl":"10.1016/j.geoen.2024.213528","url":null,"abstract":"<div><div>Polymer flooding emerges as one of the most utilized chemical enhanced oil recovery (cEOR) techniques. The implementation of acrylamide and sulfonated co-polymers holds promise in polymer flooding due to their capacity to withstand high temperatures and salinities. Taking environmental concerns into account, monitoring the quality and contamination of groundwater becomes crucial and challenging after the cEOR processes. In this study, we developed a method for the determination of acrylamide and sulfonated co-polymers potentially contaminating groundwater using high-performance liquid chromatography with diode-array detection (HPLC-DAD). To achieve the sensitivity required for such a demanding task, key parameters including the detection wavelength, mobile phase ratio, injection volume, flow rate, and temperature were optimized, which resulted in the values of 195 nm, 70% acetonitrile in pure water, 20 μL, 1 mL/min, and 30 °C, respectively. The chromatographic process was completed within a short 5-min analysis time, allowing for readily increased sample throughput. Moreover, the accuracy and precision of the proposed method for the determination of target polymers in groundwater samples were demonstrated, and the criteria were satisfactorily met in accordance with AOAC guidelines.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213528"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142698055","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}

{"title":"A phase-field modeling study for reaction instability and localized fluid flow in carbonate rocks","authors":"Kenji Furui ,&nbsp;Keita Yoshioka","doi":"10.1016/j.geoen.2024.213438","DOIUrl":"10.1016/j.geoen.2024.213438","url":null,"abstract":"<div><div>As acidic fluids flow and dissolve minerals in carbonate formations, the reaction may localize into a dendritic pattern under certain conditions known as wormhole. Wormhole is considered to be triggered by pore-scale heterogeneity in the rock that promotes preferential flow paths. Therefore, in macroscale (Darcy scale) simulation, numerical models usually need to prescribe a certain degree of macroscopic heterogeneous permeability to promote localized dissolution (wormhole). However, experimental studies have shown that wormholes form in synthetic plasters without apparent heterogeneity, implying that macroscopic heterogeneity is not a necessary prerequisite for wormhole formation and prescribed heterogeneity may impose unnecessary biases. Here, we applied a macroscale wormhole model based on a phase-field approach to demonstrate that wormhole can form in macroscopically homogeneous media as long as the inlet velocity meets the infiltration-reaction instability condition obtained from perturbation analysis. Furthermore, we simulated wormhole growth behaviors in homogeneous and heterogeneous permeability fields with the standard variance values of 0.5, 1.0 and 2.0. The simulation results showed that the normalized injectivity decreases from 3.90 to 3.15 when the standard variance changed from 0.5 to 2.0 indicating that heterogeneity may actually suppress the wormhole growth because an increasing amount of acid infiltrates into the branched wormholes. These findings suggest that permeability heterogeneities should not be treated as a trigger for wormholes in the macroscale numerical simulation. Instead, they should be regarded as parameters that influence the nucleation and growth of wormholes because the permeability field has significant effects on post-acid wormhole geometry and resultant well productivity and injectivity.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213438"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142698056","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Research on mass transfer mechanisms due to short-term water-rock interactions between granite cuttings and alkaline NaCl solution and their patterns","authors":"Ou Jiang ,&nbsp;Xiuhua Zheng ,&nbsp;Qingjie Gong ,&nbsp;Haidong Wu ,&nbsp;Baozhen Chu","doi":"10.1016/j.geoen.2024.213512","DOIUrl":"10.1016/j.geoen.2024.213512","url":null,"abstract":"<div><div>Water-rock interactions induced by working fluids in hot dry rock (HDR) reservoirs lead to reservoir damages through mass transfer. Therefore, investigating the mass transfer mechanisms due to the interactions between working fluids and reservoir rocks contributes to minimizing HDR reservoir damages. Drilling fluid is an important working fluid, yet the interactions between drilling fluids and HDR reservoir rocks lack understandings. Here, interaction experiments were conducted using a high-temperature and high-pressure flow reactor under temperatures of 180 °C and 240 °C, a pressure of 24 MPa, and a flow rate of 0.05 mL/min for 7 days. Pure water and an alkaline NaCl solution, which is referred to a HDR reservoir drilling fluid, were prepared to interact with granite cuttings from the HDR reservoir at Qiabuqia site in Gonghe Basin, Qinghai Province, China. Mineral characteristics, mass and chemical changes in the cuttings, solution element content concentrations, micro-morphology and element contents on the cuttings surface, as well as the size of suspending fines in the solutions were determined to reveal the mass transfer mechanisms. The results indicate that the mass transfer mechanisms include mineral reactions and fines migration, and fines migration is the dominating mechanism. The mineral reactions, including feldspar dissolution, quartz dissolution and feldspar alteration, are strong at the front section, while are weak at the end section. At the middle section, the released element contents by mineral reactions form various precipitates, mainly including aluminosilicate, silicate and silica. Strong mineral reactions at the front section lead to fines migration, while the precipitation of Na-bearing minerals at the middle section inhibits fines migration through a coating effect. Suspending fines are identified in the solutions, with a diameter of 100–300 nm, and settled fines are observed at the end section, with a diameter of hundreds of nanometers to a few microns. Simulations of reaction equilibrium show that the precipitation of quartz and biotite increases with a higher NaCl concentration and a lower temperature, while albite changes from dissolution to precipitation as NaCl concentration rises from 6 wt% to 12 wt%. The formation of halite by simulations supports the coating effect. This study provides theoretical basis to minimize HDR reservoir damage induced by working fluids.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213512"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142698051","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}

{"title":"Committee machine learning: A breakthrough in the precise prediction of CO2 storage mass and oil production volumes in unconventional reservoirs","authors":"Shadfar Davoodi ,&nbsp;Hung Vo Thanh ,&nbsp;David A. Wood ,&nbsp;Mohammad Mehrad ,&nbsp;Mohammed Al-Shargabid ,&nbsp;Valeriy S. Rukavishnikov","doi":"10.1016/j.geoen.2024.213533","DOIUrl":"10.1016/j.geoen.2024.213533","url":null,"abstract":"<div><div>Accurate prediction of CO₂ storage mass and cumulative oil production is critical in the context of combining subsurface carbon capture with enhanced oil recovery (CCS-EOR). This study introduces a novel committee machine-learning Gaussian Process Regression (CML-GPR) model, which integrates three well-established machine-learning algorithms—Random Forest (RF), Multi-Layer Extreme Learning Machine (MELM), and Generalized Regression Neural Network (GRNN). The combination of these models leverages the strengths of each algorithm: RF captures nonlinear relationships, MELM enhances computational efficiency, and GRNN provides smooth, generalized predictions. By integrating these complementary techniques, the CML-GPR model demonstrates significant improvements in predictive accuracy over individual models, addressing limitations in their performance. The model predicts CO₂ storage mass and cumulative oil production based on nine key reservoir input variables, including depth, porosity, and CO₂ injection rate, among others. Utilizing a large dataset of 21,193 data points from reservoir simulations, a Mahalanobis distance-based outlier detection method further refines the input data quality. The CML-GPR model achieves root mean square error (RMSE) values of 0.49 million metric tons for CO₂ storage mass and 13.68 million barrels for cumulative oil production, significantly outperforming individual models. The CML-GPR model provides a robust tool for optimizing CO₂ storage capacity and oil recovery, with practical implications for real-world reservoir management, ensuring more efficient and reliable CCS-EOR operations. This study represents a pioneering advancement in predictive modeling, offering valuable insights for optimizing both CO₂ storage and enhanced oil recovery in complex reservoirs.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213533"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142698052","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}

{"title":"Analysis of enhanced geothermal system flowback and circulation test data for fracture and reservoir characterization","authors":"A.-L.L. Benson ,&nbsp;C.R. Clarkson ,&nbsp;D. Zeinabady","doi":"10.1016/j.geoen.2024.213532","DOIUrl":"10.1016/j.geoen.2024.213532","url":null,"abstract":"<div><div>Geothermal energy has gained increasing attention worldwide, driven by the need for clean energy sources. Evaluation of subsurface properties in geothermal systems is critical for determining resource potential, optimizing energy production, and evaluating the risk of induced seismicity, amongst other applications. However, the thermal and hydraulic properties of geothermal systems are generally unknown or highly uncertain.</div><div>This study develops three models to characterize subsurface reservoirs and hydraulic fractures in EGS. A semi-analytical heat transfer model, based on thermal energy balance, and an analytical flow model, derived from material balance, are presented for history matching produced water temperatures and production rates/pressures from an EGS well doublet. Additionally, an analytical flowback model is proposed for analyzing early-time flowback data from the injection well. The models were verified through history matching simulated EGS examples, demonstrating accuracy within a ±5% error range. A geothermal doublet with reservoir heterogeneity was also simulated numerically and history-matched using the semi-analytical model, proving its broader applicability.</div><div>To demonstrate practical application of the proposed models, data from the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed. Early time flowback production data from three different stages of hydraulic fracturing of the injection well [Well 16A(78)-32] were evaluated as was data recorded at the production well [Well 16B(78)-32] during circulation testing. The outlet produced water temperatures obtained from the production well were history matched using the semi-analytical heat transfer model to estimate hydraulic fracture (fracture permeability and half-length) and reservoir thermal properties (average subsurface thermal conductivity and specific heat capacity). The early-time flowback data from the injection well were history matched using the analytical flowback model, and the resulting derived fracture properties were compared with microseismic data collected during each stage of hydraulic fracturing. The microseismic data suggest that the half-fracture height for Stage 1, Stage 2 and Stage 3 increased for each subsequent stage. This increasing trend is in agreement with the flowback model-derived fracture heights (205 ft for Stage 1; 315 ft for Stage 2 and 375 ft for Stage 3). These results underscore the need for continued research on analytical models to improve geothermal system characterization and support the advancement of geothermal energy as a sustainable power source.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213532"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142698641","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}

{"title":"Fast mass transfer processes of interfering trapped CO2-clusters at reservoir conditions: Experiment and theory","authors":"Helmut Geistlinger ,&nbsp;Bilal Zulfiqar ,&nbsp;John Maximilian Koehne ,&nbsp;Steffen Schlueter ,&nbsp;Bernd Apelt ,&nbsp;Mohammed Amro","doi":"10.1016/j.geoen.2024.213509","DOIUrl":"10.1016/j.geoen.2024.213509","url":null,"abstract":"<div><div>The gas-to-oil ratio (GOR) of a reservoir fluid plays a critical role in optimizing oil recovery and oil production strategies, improving oil recovery efficiency, and predicting reservoir behavior. Understanding the complicated kinetics of multicomponent mass transfer at the pore scale after gas injection into petroleum reservoirs is of great importance for estimating GOR and enhanced oil recovery (EOR). However, to date, there is a significant gap in the fundamental process understanding of the complex mass transfer process at reservoir conditions. Using micro-CT technology, we investigate the time dependence of CO₂ mass transfer and cluster growth after high pressure CO₂ injection into sedimented porous media (sintered 0.2 mm glass beads).</div><div>Surprisingly, the CO₂ partitioning equilibrium is already reached after 2 h. To the best of our knowledge, such a fast CO₂ transport through water-saturated porous media, which cannot be explained by linear diffusion models (time scale 100 days for a diffusion length of 10 cm), has not been reported in the literature before. We proposed a conceptual model that assumes CO₂ inflation of interfering gas clusters drives cascading CO₂ transport. We verified this conceptual model through a time series of experiments at different initial gas saturation, analyzing in each case the spatial cluster distribution, cluster size distribution, and pore occupancy frequency.</div><div>Whether CO₂ inflation of the gas clusters occurs depends on the critical initial gas saturation, which is about 10%. Our main conclusion is that CO₂ migration should be considered as gas phase diffusion cascading along a quasi-percolating cluster, since CO₂ inflation leads to a high gas saturation of about 26%, which is close to the percolation threshold. Our experimental results support this physical hypothesis. We show for the first time that CO₂ clusters can expand over large pore spaces and thus are close to the critical percolation threshold (mobility threshold). The cluster size distribution can be described by a power distribution with the critical exponent 2.19, i.e., it shows <em>universal scaling</em>.</div><div>We model the interfering mass transfer processes of neighboring gas clusters with a multi-sphere model. Exploring different scenarios for the dissolution kinetics of an ensemble of interfering gas clusters allow a deeper understanding of the complicated mass transfer kinetics and agree well with experimental cluster analyses at specific times.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213509"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142743718","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}

{"title":"A mechanistic investigation on NP-stabilized foam three phase displacement characteristics in low permeable porous media","authors":"Dong Wang,&nbsp;Mingsheng Yang,&nbsp;Xiang Su,&nbsp;Yingge Li,&nbsp;Dongxing Du","doi":"10.1016/j.geoen.2024.213526","DOIUrl":"10.1016/j.geoen.2024.213526","url":null,"abstract":"<div><div>Nanopartical (NP)-stabilized foam has found potential applications in unconventional oil recovery as well as greenhouse gas geological storage practices. In this paper, laboratory works were performed on NP-stabilized Supercritical CO₂ (ScCO₂) foam and N₂ foam three phase displacement processes in 49.5 mm length core samples with permeability around 50 mD. Experimental results show the pressure drop in NP-stabilized N₂ foam flooding process is 4.45 MPa, which is higher than 3.85 MPa in NP-stabilized ScCO₂ foam flow case. The oil recovery rate of 7.1% after NP-stabilized N₂ foam flooding, on the other hand, is lower than 9.1% after the NP-stabilized ScCO₂ foam displacement. To understand the mechanisms behind the laboratory results, numerical simulations were carried out with help of the mechanistic Stochastic Bubble Population Balance (SBPB) model. By taking into account the distinct differences on bubble densities as well as the rheological characteristics between NP-stabilized ScCO₂ foam and N₂ foam, together with the additional resistance factors to the water and oil phases in foam flooding processes, the numerical results reproduce satisfactorily the experimental findings on flooding pressure drops as well as oil recovery rates in both foam systems. At last, the foam three phase displacement characteristics, including the dynamic variation behavior of the three phase fluid saturation, the inlet pressure and the bubble density, were numerically investigated. It is expected this study could help understand the NP-stabilized foam flooding behaviors in low permeability porous media.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"245 ","pages":"Article 213526"},"PeriodicalIF":0.0,"publicationDate":"2024-11-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142699105","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}