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Abstract Hydrogen co-firing in a gas turbine is believed to cover an energy transition pathway with green hydrogen as a driver to lower the carbon footprint of existing thermal power generation or cogeneration plants through the gradual increase of hydrogen injection in the existing natural gas grid. Today there is limited operational experience on co-combustion of hydrogen and natural gas in an existing gas turbine in an industrial environment. The ENGIE owned Siemens SGT-600 (Alstom legacy GT10B) 24 MW industrial gas turbine in the port of Antwerp (Belgium) was selected as a demonstrator for co-firing natural gas with hydrogen as it enables ENGIE to perform tests at higher H2 contents (up to 25 vol%) on a representative turbine with limited hydrogen volume flow (1 truck load at a time). Several challenges like increasing risk of flame flashback due to the enhanced turbulent flame speed, avoiding higher NOx emissions due to an increase of local flame temperature, supply and homogeneous mixing of hydrogen with natural gas as well as safety aspects have to be addressed when dealing with hydrogen fuel blends. In order to limit the risks of the industrial gas turbine testing a dual step approach was taken. ENGIE teamed up with the German Aerospace Center (DLR), Institute of Combustion Technology in Stuttgart to perform in a first step scaled-burner tests at gas turbine relevant operating conditions in their high-pressure combustor rig. In these tests the onset of flashback as well as the combustor characteristics with respect to burner wall temperatures, emissions and combustion dynamics were investigated for base load and part load conditions, both for pure natural gas and various natural gas and hydrogen blends. For H2 < 30 vol% only minor effects on flame position and flame shape (analyzed based on OH* chemiluminescence images) and NOx emission were found. For higher hydrogen contents the flame position moved upstream and a more compact shape was observed. For the investigated H2 contents no flashback event was observed. However, thermo acoustics are strongly effected by hydrogen addition. In general, the scaled-burner tests were encouraging and enabled the second step, the exploration of hydrogen limits of the second generation DLE burner installed in the engine in Antwerp. To inject the hydrogen into the industrial gas turbine, a hydrogen supply line was developed and installed next to the gas turbine. All tests were performed on the existing gas turbine hardware without any modification. A test campaign of several operational tests at base and part load with hydrogen variation up to 25 vol% has been successfully performed where the gas composition, emissions, combustion dynamics and operational parameters are actively monitored in order to assess the impact of hydrogen on performance. Moreover, the impact of the hydrogen addition on the flame stability has been further assessed through the combustion tuning. The whole test campaign has been executed while the gas turbine stayed online, with no impact to the industrial steam customer. It has been proved that co-firing of up to 10% could be achieved with no adverse effects on the performance of the machine. Stable operation has been observed up to 25%vol hydrogen co-combustion, but with trespassing the local emission limits.

This paper advocates for a progressive rethinking of the day-ahead/intra-day power system security management practice in the low-carbon energy transition era. As a starting point, the need for coordination between multi-area transmission system operators in order to efficiently exploit the value of grid flexibility towards operating the low-carbon, multi-area power system securely and economically is emphasized. On this basis, the core proposal of this paper is the adoption of a new approach to day-ahead/intra-day multi-area power system security management, inspired by the principles of cooperative game theory. The proposed approach relies on counterfactual analysis to evaluate the (positive and/or negative) impact of each distinctive control area to the common security of the multi-area system, thus providing clear economic incentives to achieve the required coordination. This proposal is not a marginal approach and notably facilitates the integration of more detailed physical modelling (including the non-convexities of the power system) in the inter-TSO settlement of the multi-area interconnected system security management cost. The proposed framework allows some level of subsidiarity and the definition of hedging products to cover ex-post costs. Further from the blueprint of the proposed approach, the paper presents a demonstrative implementation in the context of static N-1 security management and discusses prominent research and development pathways in order to progressively put such vision into practice.This article is part of the theme issue ‘The mathematics of energy systems’.