Gas Science and Engineering最新文献

{"title":"Evaluation of CO2 leakage potential through fault instability in CO2 geological sequestration by coupled THMC modelling","authors":"Lian Chen ,&nbsp;Derek Elsworth ,&nbsp;Jianye Chen ,&nbsp;Quan Gan","doi":"10.1016/j.jgsce.2024.205486","DOIUrl":"10.1016/j.jgsce.2024.205486","url":null,"abstract":"<div><div>A faulted saline aquifer system was simulated in a coupled thermal-hydraulic-mechanical-chemical (THMC) framework to examine the potential breaching of the caprock seal from long-term CO₂ sequestration. The pH of the brines steadily dropped from 7.5 to 4.7 due to the continuous injection of scCO₂ (supercritical CO₂), which was caused by the rapid dissolution of calcite in the reservoir and associated fault zones, alongside alterations in the concentrations of primary and secondary minerals within the formation. The increase in pore pressure with the continuous injection of scCO₂ triggered fault reactivation at 6y with the resultant leakage of CO₂ along the fault. This builds CO₂ saturation inside the fault at 7y to six-fold higher than pre-slip. Continuing shear reactivation and creation of reactive surface area following the initial CO₂ leakage accelerates dissolution/precipitation reactions, in turn further increasing porosity and permeability of the reservoir and fault. In particular, the permeability and porosity in the fault zone were increased by only 2% and 6%, respectively – staunched by competitive feedbacks in dissolution countered by precipitation that are individually much larger. Comparison of mineral concentrations adjacent to the fault before-and-after instability revealed that the development of shear failure also promotes the transport of reactivated minerals into the fault zone. Among them, feldspar changes most significantly in later stages, dominated by dissolution with the volume fraction decreasing by 80% and increasing the aqueous concentration of <em>K</em>⁺ by approximately an order of magnitude. However, secondary minerals counter this dissolution through precipitation with the volume fraction of kaolinite increasing by an order of magnitude compared with the original fraction. Finally, the evolution of the fault sealing coefficient (<em>F</em>_S) demonstrates that the porosity and permeability exert a pivotal influence in controlling the self-sealing behavior in the basal of the fault, while the upper fault layer exhibits self-enhancing response. A notable observation is that changes in mineral ion concentrations in fault zones could be applied as a significant diagnostic signal to monitor fault stability and the potential for progress of self-sealing behavior.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"132 ","pages":"Article 205486"},"PeriodicalIF":0.0,"publicationDate":"2024-11-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142655745","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":"Microscopic scale influence of functional groups on the displacement behavior of coalbed methane by hot humid flue gas: A molecular simulation study based on the dynamic injection process","authors":"Jing Huang ,&nbsp;Cheng Zhai ,&nbsp;Yong Sun ,&nbsp;Yongshuai Lai ,&nbsp;Hongyang Xu ,&nbsp;Ting Huang ,&nbsp;Yu Wang ,&nbsp;Yujie Li ,&nbsp;Jizhao Xu","doi":"10.1016/j.jgsce.2024.205477","DOIUrl":"10.1016/j.jgsce.2024.205477","url":null,"abstract":"<div><div>Building upon the CO₂-ECBM technology (CO₂-Enhanced Coaled Methane Recovery Technology), hot flue gas injection for displacing coalbed methane has been proposed to improve methane recovery efficiency and reduce the costs associated with CO₂ capture during the displacement process as well as flue gas desulfurization and denitrification at coal-fired power plants. To explore the microscopic mechanisms of displacement and the influence of functional groups, this study used Molecular Dynamics (MD) and Grand Canonical Monte Carlo (GCMC) methods with Materials Studio software to model slit pores grafted with various functional groups for gas adsorption simulations. The adsorption characteristics of eight key functional groups (-C=OCH₃, -COOH, -CH₂OH, Ar-OH, -OCH₃, -C₆H₆, -CH₃, -CH₂) for hot flue gas and methane were analyzed, focusing on adsorption strengths and underlying mechanisms. Simulations of the dynamic injection of hot flue gas were conducted, monitoring energy changes and methane density distribution to establish the relationship between adsorption strength and the difficulty of coalbed methane (CBM) displacement. The results indicate that in this simulation, the methane displacement efficiency using hot flue gas to displace coalbed methane exceeded 98%, demonstrating significantly better displacement performance compared to the use of pure carbon dioxide or nitrogen. Although both methane and hot flue gas show that greater interaction energy with pores makes displacement more difficult, the underlying causes differ. A comparison of the interaction energies between different functional groups and various gases reveals that oxygen-containing functional groups (-C=OCH₃, -COOH, -CH₂OH, Ar-OH, -OCH₃) are unfavorable for the displacement of coalbed methane by wet hot flue gas, whereas aliphatic hydrocarbons (-CH₃, -CH₂) facilitate the displacement process.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205477"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142553347","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":"Advancing carbon capture technologies in CCS: A comprehensive review of pre-combustion processes","authors":"Pouya Vaziri ,&nbsp;Mohammad Reza Rasaei ,&nbsp;Sogand Seyfoori ,&nbsp;Shiva Zamani ,&nbsp;Milad Mahmoodi ,&nbsp;Behnam Sedaee","doi":"10.1016/j.jgsce.2024.205481","DOIUrl":"10.1016/j.jgsce.2024.205481","url":null,"abstract":"<div><div>As global concern over greenhouse gas emissions intensifies, the advancement of effective carbon capture and storage technologies becomes crucial for mitigating climate change. This review comprehensively examines pre-combustion carbon capture methods, emphasizing their technical mechanisms, benefits, and challenges. We investigate a range of separation techniques, including absorption, adsorption, membrane separation, and cryogenic processes, assessing their effectiveness in capturing carbon dioxide from industrial processes before combustion. Additionally, we explore the innovative approach of micro-algae cultivation for biological carbon sequestration. By evaluating operational carbon capture and storage projects from around the world, we provide insights into current implementations and global commitments to carbon capture and storage. Additionally, we discuss the economic aspects of carbon capture and storage, highlighting the importance of financial considerations in the adoption and scalability of these technologies. Our detailed technical analysis highlights the scalability, energy consumption and environmental viability of various pre-combustion capture technologies. We also discuss the ongoing research efforts and technological advancements driving improvements in these methods. The review underscores the importance of continued innovation and collaborative efforts to enhance carbon capture technologies, aiming for substantial reductions in greenhouse gas emissions and effectively addressing the multifaceted challenges of climate change.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205481"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142571903","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":"Numerical modelling of CO2-in-water emulsion injection into a water-saturated core","authors":"Aabes Bahmaee ,&nbsp;Yoshihiro Masuda ,&nbsp;Sumihiko Murata","doi":"10.1016/j.jgsce.2024.205485","DOIUrl":"10.1016/j.jgsce.2024.205485","url":null,"abstract":"<div><div>Depressurization method shows promise for methane hydrate (MH) reservoir production, but the reformation of hydrates due to a lack of geothermal heat presents a significant challenge for commercial production. This study proposes a novel approach for MH gas recovery by injecting a CO₂-in-water (C/W) emulsion into an MH reservoir aquifer. The exothermic nature of CO₂ hydrate formation and liquid CO₂ dissolution in water in this method provides heat to the MH layer, effectively preventing hydrate reformation. Subsequently, 1-D numerical models were developed and implemented using the MATLAB Reservoir Simulation Toolbox (MRST). These models were rigorously validated against experimental data under homogeneous conditions and varying injection schemes. The investigation indicated that the average volume fraction of CO₂ hydrate within the hydrate particles was found to be 55% of the volume of liquid CO₂ droplets. The alternating C/W emulsion injection increased the driving force for CO₂ dissolution in water, thereby promoting subsequent hydrate particle decomposition and CO₂ hydrate dissolution in water, which effectively mitigated blockage within the porous medium. In conclusion, water alternating C/W emulsion injection, along with the continuous injection of a low volume fraction of liquid CO₂ within the C/W emulsion, exhibits promising potential for sustained injection and provides adequate heat to the MH layer, preventing hydrate reformation. Furthermore, the developed numerical model reasonably predicts the behavior of various injection schemes. This developed model can be used for devising long term sub-seabed carbon capture and storage development plan.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205485"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142571930","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":"Enhancing shale gas EUR predictions with TPE optimized SMOGN: A comparative study of machine learning algorithms in the marcellus shale with an imbalanced dataset","authors":"Yildirim Kocoglu ,&nbsp;Sheldon Burt Gorell ,&nbsp;Hossein Emadi ,&nbsp;Athar Hussain ,&nbsp;Farshad Bolouri ,&nbsp;Phillip McElroy ,&nbsp;Marshal Wigwe","doi":"10.1016/j.jgsce.2024.205475","DOIUrl":"10.1016/j.jgsce.2024.205475","url":null,"abstract":"<div><div>Oil and gas operators frequently rely on traditional methods to predict Estimated Ultimate Recovery (EUR) but, these methods often fail to accurately predict shale gas EUR. Therefore, machine learning (ML) algorithms were shown as promising alternatives but, the negative effects of imbalanced datasets on their performance still remains underexplored. This study addresses this gap with a Tree-Parzen Estimator (TPE) optimized Synthetic Minority Over-sampling Technique for Regression with Gaussian Noise (SMOGN) to alleviate the detrimental effects of the imbalanced datasets on model performance. Two cases were compared: one employed standard pre-processing while, the other employed TPE optimized SMOGN. Four ML algorithms: Artificial Neural (ANN), Deep-ANN, Support Vector Regression (SVR), and eXtreme Gradient Boosting (XGBoost) were trained across both cases with an imbalanced dataset of 460 Marcellus shale wells. Exploratory data analysis revealed that the imbalance was due to the evolution of completion techniques, leading to the underrepresentation of wells completed with more recent, aggressive methods. The proposed framework improved <span><math><mrow><msup><mi>R</mi><mn>2</mn></msup></mrow></math></span> of the models from 0.8243 to 0.8934 to 0.8851–0.9186 with more significant gains in the underrepresented wells in the higher EUR regions (<span><math><mrow><mo>&gt;</mo><mn>1.5</mn><mo>×</mo><msup><mn>10</mn><mn>7</mn></msup><mspace></mspace><mtext>Mscf</mtext></mrow></math></span>), where the <span><math><mrow><msup><mi>R</mi><mn>2</mn></msup></mrow></math></span> improved from 0.2155 to 0.4598 to 0.5615–0.9472. The SMOGN enhanced SVR had the highest computational efficiency (<span><math><mrow><mo>&lt;</mo><mn>1</mn><mspace></mspace><mtext>second</mtext></mrow></math></span> to train) and highest performance <span><math><mrow><mo>(</mo><msup><mi>R</mi><mn>2</mn></msup></mrow></math></span> of 0.9472) in these higher EUR regions, while the SMOGN enhanced Deep-ANN had the highest overall performance (<span><math><mrow><msup><mi>R</mi><mn>2</mn></msup></mrow></math></span> of 0.9186). This framework outperforms standard pre-processing frameworks. Additionally, it enables operators to predict shale gas EUR more accurately for future infill wells completed with recent techniques, even while the wells are still producing in transient flow, facilitating early cost-saving decisions. To the best knowledge of the authors, this is the first research that proposed TPE optimized SMOGN to improve shale gas predictions.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205475"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142571931","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":"Cost minimization of membrane-based separation systems for H2 recovery: A comparison of two optimization approaches","authors":"Carlos D. Fischer ,&nbsp;Miguel C. Mussati ,&nbsp;Tatiana Morosuk ,&nbsp;Sergio F. Mussati","doi":"10.1016/j.jgsce.2024.205479","DOIUrl":"10.1016/j.jgsce.2024.205479","url":null,"abstract":"<div><div>This paper addresses the optimization of membrane-based processes, with a specific focus on H₂ recovery in hydrocarbon processing plants. A comparative analysis of two optimization approaches is conducted for designing H₂ recovery systems for a multicomponent gas mixture containing H₂/N₂/CO₂/CO. The main objective is to achieve the desired H₂ recovery and product purity levels while minimizing costs. The paper compares two approaches for optimization: the first uses a simulation-based optimization technique with Aspen Custom Modeler/ASPEN Plus, while the second employs a simultaneous optimization method using GAMS (General Algebraic Modeling System). The methods are thoroughly compared, evaluating their strengths and weaknesses through qualitative and numerical assessments. To this end, a reference case was selected from the existing literature. The results obtained indicate that both proposed approaches are suitable for optimizing the design of a two-stage membrane configuration, as evidenced by the similarity of the optimal solutions obtained from both approaches. Subsequently, based on the analysis of numerical values for the optimal design problem for the investigated two-stage membrane configuration, a hybrid strategy for the optimal synthesis and design of multi-stage separation processes is proposed.</div><div>The study fills a gap in the literature by providing a comprehensive analysis of the advantages and disadvantages of optimization approaches in the context of technology of separation of gases. This research provides valuable insights into the field and offers guidance for selecting appropriate approaches to improve the efficiency and cost-effectiveness of gas separation processes in real-world applications.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205479"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142571932","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":"PIM-1 based mixed matrix membranes with MOF-808(Ce) for CO2 separations","authors":"Xuebi Du ,&nbsp;Dawei Shao ,&nbsp;Yinhua Wan","doi":"10.1016/j.jgsce.2024.205476","DOIUrl":"10.1016/j.jgsce.2024.205476","url":null,"abstract":"<div><div>Metal-organic frameworks (MOFs) have shown potential as nanofillers for the selective capture of specific gases in mixed matrix membranes (MMMs). This study introduces an efficient method, utilizing a mild (100 °C) reaction condition and a short reaction time (20 min), for the synthesis of MOF-808(Ce) nanocrystals. The MOF-808(Ce) that is obtained exhibits porous characteristics, a notable affinity for CO₂, and robust intermolecular interactions with PIM-1. Furthermore, this study pioneers the incorporation of MOF-808(Ce) as a filler into PIM-1, with varying loadings, to create PIM/MOF-808 MMMs for the purpose of CO₂ separation. Consequently, the MMMs containing 2 wt% MOF-808(Ce) demonstrate high CO₂ permeability of 6854 Barrer and CO₂/N₂ selectivity of 23.2, which is far surpasses 2008 upper bound from Robeson and approaches the refined 2019 upper bound from MeKenow. A comparative analysis demonstrates the efficacy of MOF-808(Ce) as a filler in PIM-1 for the purpose of CO₂ separation.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205476"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142561150","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":"Impact of gas adsorption of nitrogen, argon, methane, and CO2 on gas permeability in nanoporous rocks","authors":"Sheng Peng ,&nbsp;Harun Ates ,&nbsp;Tongwei Zhang ,&nbsp;Shannon L. Eichmann ,&nbsp;Anuj Gupta","doi":"10.1016/j.jgsce.2024.205478","DOIUrl":"10.1016/j.jgsce.2024.205478","url":null,"abstract":"<div><div>Gas adsorption on the surface of nanoporous rocks is an important process that occurs in many applied scenarios such as shale gas production or CO₂ enhanced gas recovery or storage. While there are few theoretical considerations on the effect of gas adsorption on permeability, a systematic laboratory investigation of the impact of gas adsorption on gas flow and permeability is still lacking. In this paper, permeability of four adsorptive gases, i.e., nitrogen, argon, methane, and carbon dioxide, was measured, along with helium permeability, for two nanoporous rock samples that have high and low total organic carbon (TOC) content, respectively. The measurements were conducted at a range of pore pressures from 150 to 1500 psi (1.03–10.34 MPa). Gas adsorption isotherms were also measured at the same conditions. A mathematical model that considers adsorption with specific boundary conditions for the experimental setup was used for data analysis. The results show that gas adsorption causes larger drop in pressure decay and greater retardation in pressure equilibrium. However, the reduction of permeability relative to helium (25%–46%) is similar for gases with different levels of adsorption, indicating the occurrence of single-layer adsorption for these gases. Comparison between the two samples further supports the concept of single-layer adsorption and signifies the impact of pore size on the permeability reduction due to adsorption. These new findings deepen the fundamental understanding and provide important clarification on the effect of gas adsorption on gas flow and permeability in nanoporous rocks.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205478"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142553345","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":"Comprehensive characterizations of core sediments recovered from Shenhu W17 well in South China sea and its impact on methane hydrate kinetics","authors":"Yan Li ,&nbsp;Chenlu Xu ,&nbsp;Jianxi Zhu ,&nbsp;Hongfeng Lu ,&nbsp;Yunting Liu ,&nbsp;Yuhang Gu ,&nbsp;Zhejun Pan ,&nbsp;Praveen Linga ,&nbsp;Zhenyuan Yin","doi":"10.1016/j.jgsce.2024.205482","DOIUrl":"10.1016/j.jgsce.2024.205482","url":null,"abstract":"<div><div>Natural Gas Hydrates (NGH) is considered a vast unconventional energy source that holds significant promise in addressing future energy demands. In Shenhu area (located at northern slope of the South China Sea, SCS), there has been conducted a series of further studies of NGH such as exploration, drilling, and twice field production testing. The lithological characteristics of cores from marine sediments and their influence on methane hydrate (MH) formation are relatively unknown and merits further investigation. In this study, we conducted a chain of lithological characterization on the core sediments recovered from Shenhu W17 well, the coring well which located near the 1^st NGH field production in SCS. The core sediments are classified as clayey-silt, its median grain size is 6.91 μm, comprising primarily clay minerals, quartz, and calcite. According to X-ray diffraction analysis, the main content of clay minerals is illite-smectite layers, illite, chlorite, and kaolinite, respectively. Porosity of the core sediments is 32.5% and the permeability is 7.8 mD based on mercury intrusion tests. Four types of primary pores are identified based on SEM and QEMSCAN analysis: intergranular pore, intercrystalline pore, intragranular pore, and pores associated with marine fossils. Moreover, the influence of the recovered core sediments (0–40 wt%) on MH formation kinetics were examined with morphology observed to elucidate the MH-core sediments interaction. The induction time was reduced significantly to ∼20 min in the presence of SCS core sediments. A two-stage MH formation behavior is observed with a maximum gas uptake of 134.1 <em>V</em>_g·<em>V</em>_w⁻¹: (a) an initial MH formation at the gas-liquid interface with MH upward growth and fine-grain sediments migration; and (b) a second stage of significant MH growth with layered formation of MH and core sediments. The capillary channels of MH formed facilities the migration of core sediments, which in turn provides additional gas-liquid contact area for MH formation. The study provides valuable insights on the role Shenhu core sediments in MH formation, which is essential for understanding the spatial heterogeneity of NGH in reservoir and for designing suitable production strategy.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205482"},"PeriodicalIF":0.0,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142560897","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":"Kinetics of CO2 hydrate formation in clayey sand sediments: Implications for CO2 sequestration","authors":"Abdirahman Hassan Mohamed ,&nbsp;Aliyu Adebayo Sulaimon ,&nbsp;Haylay Tsegab ,&nbsp;Bhajan Lal ,&nbsp;Aneel Jordan Atthi Tasan Singh ,&nbsp;Syahrir Ridha","doi":"10.1016/j.jgsce.2024.205483","DOIUrl":"10.1016/j.jgsce.2024.205483","url":null,"abstract":"<div><div>Hydrate-based CO₂ sequestration beneath oceanic sediments is an emerging technique that involves the injection of CO₂ into the hydrate stability zone (HSZ) beneath the seabed, forming hydrate cap that structurally traps the injected CO₂ and reduces the risk of leaking CO₂ from the storage sediment. Gas hydrates are adequately stable in sand sediments saturated with fresh water; however, the salinity of oceanic water impairs hydrate formation kinetics, stability, and CO₂ storage capacity. In addition to sandstones, marine sediments are composed of many clay minerals that could affect hydrate formation. Therefore, this study experimentally simulates CO₂ injection into sand and clayey sand sediments to assess the potential of CO₂ hydrate formation. CO₂ hydrates are formed inside a high-pressure reactor, which contains unconsolidated sediment bed/pack (silica sand; mixed sand with bentonite clay: 5 wt% and 10 wt%), saturated with de-ionized water or brine (3.3 wt% NaCl). Hydrate formation experiments were performed at 4 MPa pressure and 274.15 K temperature. Results show that CO₂ hydrate formed within the sand sediment, with induction times of 6 and 8.5 h, for the de-ionized and brine systems, respectively. CO₂ gas mole uptake in the de-ionized system was 71.54 mmol/mol however, in the brine system the gas uptake was 56.95 mmol/mol. Hence this 20.4% reduction in the gas uptake indicated the inhibition effect of salinity. In contrast, in the brine-saturated 5 wt% clay-sand sediment, the induction time was 6.5 h, indicating the promoting effect of the nano-sized clay particles. However, the gas uptake in this brine-saturated clay-sand sediment was reduced by 45.51% compared to the brine-saturated sand sediment. Increasing the clay content to 10 wt% prevented CO₂ hydrate formation due to porosity reduction. Moreover, de-ionized water in clayey sand sediments prevented hydrate formation due to clay swelling. Finally, CO₂ hydrate formation at the end of each experiment was visually confirmed.</div></div>","PeriodicalId":100568,"journal":{"name":"Gas Science and Engineering","volume":"131 ","pages":"Article 205483"},"PeriodicalIF":0.0,"publicationDate":"2024-10-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142539557","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}