Smart Gas Network with Linepack Managing to Increase Biomethane Injection at the Distribution Level

The current situation in Europe calls for the need of urgent measures to find sustainable alternatives to its outer dependence on natural gas. Biomethane injection into the existing gas infrastructure is a fundamental opportunity to be promoted that, however, causes increasing complexities in the management of natural gas grids. At the gas distribution level, the lack of a monitoring system and suitable software for the simulation, management, and verification of gas networks may act as barriers to a widespread diffusion of a biomethane production and injection chain. A transient fluid-dynamic model of the gas network is developed to perform estimations of the natural gas grid capacity in situations of production-consumption mismatch, taking into account the linepack as a gas buffer stock. The model is applied to the gas distribution network of a small urban-rural area. The aim is to assess the role of the linepack in determining the gas network receiving capacity and to test smart management of pressure set-points and injection flow rate to minimize biomethane curtailment. Results show that biomethane unacceptability can be reduced to 10% instead of 27% (obtained when following the DSOs state-of-the-art current procedures), thus highlighting the importance of the implementation of transient simulation software but also underlining the need for smarter control systems, actuators, and data management platforms for a transition to smart digital gas grids

A Review of the Energy System and Transport Sector in Uzbekistan in View of Future Hydrogen Uptake

This study explores the potential role of hydrogen in decarbonizing the transport sector in Uzbekistan by examining different aspects of the country's energy system and transport final use. In road transport, Uzbekistan has already gained experience with the use of alternative fuels through the "Compressed Natural Gas-Mobility" initiatives and has achieved a fleet coverage of 59%. These existing frameworks and knowledge can ease the integration of hydrogen into road transport. The rail sector also has the potential for hydrogen uptake, considering that 47% of rail lines are not electrified. The results of this study indicate that powering all CNG vehicles with a 10% hydrogen blend (HCNG) could reduce road transport emissions by 0.62 MtCO2eq per year, while replacing diesel trucks with hydrogen-based vehicles could contribute to an additional reduction of up to 0.32 MtCO2eq per year. In rail transport, hydrogen-powered trains could reduce emissions in non-electrified lines by up to 0.1 kgCO2eq/km of journey. In assessing the potential infrastructure for hydrogen logistics, this study also identifies opportunities for hydrogen export by repurposing the existing natural gas infrastructure. Focusing on Uzbekistan, this study provides a regional perspective on the potential for the integration of hydrogen into the transport sector in Central Asia

Solar hydrogen for high capacity, dispatchable, long-distance energy transmission - A case study for injection in the Greenstream natural gas pipeline

This paper presents the results of techno-economic modelling for hydrogen production from a photovoltaic battery electrolyser system (PBES) for injection into a natural gas transmission line. Mellitah in Libya, connected to Gela in Italy by the Greenstream subsea gas transmission line, is selected as the location for a case study. The PBES includes photovoltaic (PV) arrays, battery, electrolyser, hydrogen compressor, and large-scale hydrogen storage to maintain constant hydrogen volume fraction in the pipeline. Two PBES configurations with different large-scale storage methods are evaluated: PBESC with compressed hydrogen stored in buried pipes, and PBESL with liquefied hydrogen stored in spherical tanks. Simulated hourly PV electricity generation is used to calculate the specific hourly capacity factor of a hypothetical PV array in Mellitah. This capacity factor is then used with different PV sizes for sizing the PBES. The levelised cost of delivered hydrogen (LCOHD) is used as the key techno-economic parameter to optimise the size of the PBES by equipment sizing. The costs of all equipment, except the PV array and batteries, are made to be a function of electrolyser size. The equipment sizes are deemed optimal if PBES meets hydrogen demand at the minimum LCOHD. The techno-economic performance of the PBES is evaluated for four scenarios of fixed and constant hydrogen volume fraction targets in the pipeline: 5%, 10%, 15%, and 20%. The PBES can produce up to 106 kilotonnes of hydrogen per year to meet the 20% target at an LCOHD of 3.69 €/kg for compressed hydrogen storage (PBESC) and 2.81 €/kg for liquid hydrogen storage (PBESL). Storing liquid hydrogen at large-scale is significantly cheaper than gaseous hydrogen, even with the inclusion of a significantly larger PV array that is required to supply additional electrcitiy for liquefaction

Pressure management in smart gas networks for increasing hydrogen blending

The injection of hydrogen into existing gas grids is acknowledged as a promising option for decarbonizing gas systems and enhancing the integration among energy sectors. Nevertheless, it affects the hydraulics and the quality management of networks. When the network is fed by multiple infeed sites and hydrogen is fed from a single injection point, non-homogeneous hydrogen distribution throughout the grid happens to lead to a reduction of the possible amount of hydrogen to be safely injected within the grid. To mitigate these impacts, novel operational schemes should therefore be implemented. In the present work, the modulation of the outlet pressures of gas infeed sites is proposed as an effective strategy to accommodate larger hydrogen volumes into gas grids, extending the area of the network reached by hydrogen while keeping compliance with quality and hydraulic restrictions. A distribution network operated at two cascading pressure tiers interfaced by pressure regulators constitutes the case study, which is simulated by a fluid-dynamic and multi-component model for gas networks. Results suggest that higher shares of hydrogen and other green gases can be introduced into existing distribution systems by implementing novel asset management schemes with negligible impact on grid operations

Hydrogen blending into the gas distribution grid: the case study of a small municipality

Hydrogen blending into the gas network may offer an alternative concept for the storage of the exceeding energy from renewable power sources, improving the flexibility of the energy system through the integration of the electricity and gas networks. This scenario foresees the use of electrolyzers to convert power into hydrogen gas. The gas grid could both provide storage and act as the transport facility of the produced gas, taking advantage of the robustness and extensiveness of an already existing energy infrastructure. In this work, a steady state and multi-species thermal-fluid-dynamic model of the gas network is applied to a portion of the Italian distribution network, located in EmiliaRomagna, covering a surface of 2,900 ha and having a throughput of 8.25 MSm3 /year of natural gas. The receiving potential capacity of the existing infrastructure is assessed with respect to hydrogen injection. Fluid-dynamic effects of the hydrogen blending are considered and commented. The maximum allowable percentage of injectable hydrogen is calculated on a nodal basis, referring to the actual gas network configuration. The current Italian regulation on distributed injection (DM 19/02/2007) of gases into the natural gas network only allows injecting gases having nearly the same quality of natural gas (UNI-EN 437), thus excluding any blending practice. However, in the simulated scenario here proposed, it is assumed that gas quality requirements are on the network as a whole (i.e., after blending of hydrogen in the grid) rather than at the single injection point. By exploiting the qualitytracking feature of the model, the constraint of quality assessment at the injection point is thus relaxed. Once the blending limit is known for each node, the amount of injectable hydrogen is calculated accordingly, taking into account the amount of natural gas already flowing through the node itself. The node with the major injection capability is the designated one for the injection and used for the simulation of the case study. Finally, a comparison between the ‘base case’ and the ‘maximum hydrogen injection case’ is presented and discussed showing how hydrogen blending into the gas grid may lead to a reduction on the fossil natural gas supply of up to 2,1%

Electrical and gas networks coupling through hydrogen blending under increasing distributed photovoltaic generation

Electricity and gas infrastructure coupling has the twofold effect of solving production-consumption mismatches and decarbonizing the natural gas system through power-to-gas technologies producing hydrogen to be injected within the gas network. However, little is known on how this may impact the gas network operation, especially at a local level. This paper aims to fill this gap by presenting a methodology for modeling the interactions between electricity and gas distribution networks through the implementation of their physical models. A scenario of increasing penetration of distributed photovoltaic production is considered for a sample urban area. Whenever photovoltaic production exceeds the urban area consumption, hydrogen is produced and injected into the gas network. 24 injection scenarios were examined and compared to evaluate their impacts on fluid-dynamics and the quality of gas blends. Results show possible bottlenecks against hydrogen injection caused by the gas network. During summertime operations and in the cases of injection following directly the solar over-production, the hydrogen share peaks 20–30% already in the scenario of 40% solar penetration, generating unacceptable blends. These gas quality perturbations are considerably reduced when hydrogen is injected constantly throughout the day. The choice of the injection node also contributes to perturbation reduction. Sector coupling through hydrogen blending results in a complex interplay between renewable energy excess and local gas network availability which can be enhanced by buffer storage solutions and proper choice of injection node. In the framework of integrated and multi-gas systems, combined simulation tools are necessary to evaluate sector-coupling opportunities case-by-case

Il dialogo tra diritto ecclesiastico e diritto costituzionale

Fifty years after the conference in which Law and Religion Scholars held a dialogue with Constitutional Scholars in Siena, central issues of that discussion are recalled, and those of a future debate are envisaged, with the hope that both disciplines might benefit from i

Multicenter randomized clinical trial of lateral-trendelenburg vs. semi recumbent position for the prevention of ventilatorassociated pneumonia - the gravity-VAP trial

Introduction: Gravity plays a pivotal role in the pathogenesis of ventilator-associated pneumonia (VAP) (1). In previous laboratory studies (2) the semi-lateral Trendelenburg position (LTP) hindered gravity-driven pulmonary aspiration and avoided VAP. Objectives: To determine whether the LTP vs. the semi-recumbent position (SRP) would reduce the incidence of microbiologically confirmed VAP and to appraise patient's compliance and safety. Methods: We conducted a randomized, single-blind, controlled study in 17 European centers and 1 in North America. A total of 2019 adult patients were screened between 2010 and 2015. 395 patients were randomized - 194 in LTP and 201 in SRP - and analyzed in an intention to treat approach. Patients in LTP were placed in semi-lateral (60°) - Trendelenburg position to achieve an orientation, from the sternal notch toward the mouth, slightly below horizontal, and turned from one side to the other every 6 hours. LTP was encouraged during the first days of mechanical ventilation, but always in compliance with the patient's wish. In the SRP group, the head of the bed was elevated ≥ 30°. Primary outcome was VAP incidence rate, based on quantitative bronchoalveolar lavage fluid culture with ≥ 104 colonyforming units/mL. Secondary outcomes were compliance to the randomized position, length of intubation, duration of intensive care unit and hospital stay, mortality, and adverse events. Results: The trial was stopped after the planned interim analysis for achieving efficacy endpoints and owing to safety concerns. Patients in the LTP and SRP group were kept in the randomized position for 38 % and 90 % of the study time, respectively (p = 0.001). Yet, during the first 48 hours, LTP patients were kept in the randomized position for 50 % of the study time, and SRP patients for 88 % (p = 0.001). In the LTP, the bed was angulated 5.6° in Trendelenburg; while, the head of the bed was elevated 34.1° in the SRP group. Incidence rates of microbiologically confirmed VAP were 0.88 (1/1136 patient-days; 95 % confidence interval [CI], 0.12-6.25) in the LTP group, and 7.19 (8/1113 patient-days; CI 95 %, 3.60-14.37) in the SRP (p = 0.020), relative risk reduction of 0.12 (95 % CI, 0.01-0.91). No statistically significant differences were observed in durations of mechanical ventilation, intensive care unit and hospital stay, and mortality. Vomiting was more common in LTP patients (8.3 % vs. 2.5 % in the SRP, p = 0.013). Conclusions: Critically ill patients positioned in the LTP had a statistically significant reduction in the incidence of VAP, compared with those positioned in the SRP. A comprehensive evaluation of potential LTP contraindications is warranted to enhance safety