• Energy Research

A new process concept integrating power to methane with top gas recycling in an oxygen blast furnace (BF) is investigated to reduce the emission intensity of steelmaking. Power to gas produces synthetic methane using hydrogen (H2) generated by an electrolyser operated with renewable electricity, and CO2 captured from the BF gas by amine scrubbing supplied with heat from the methanation process. The clean gas from the amine scrubbing is recycled and injected in the BF (via top gas recycling), together with synthetic methane. A parametric analysis is performed to vary the amount of top gas recycled (from 0 kg/tHM to 270 kg/tHM). Based on the results, CO2 equivalent emissions can decrease by 34% using power to gas technology, and by 30% with power to gas and top gas recycling (compared to conventional BFs). Nevertheless, if both integrations are present, additional benefits on the specific energy consumption (12.0 MJ/tHM), and specific cost (130 €/tHM) are achieved, compared to only applying power to gas (17.5 MJ/tHM and 233 €/tHM). In all cases, the downstream thermal energy needs of the steel plant are fulfilled, contrarily to conventional top gas recycling concepts. The main conclusion is that top gas recycling should be considered together with PtG technology, and vice versa, when integrated in blast furnace ironmaking, in order to both abate emissions while supplying downstream energy needs.

A new process concept integrating power to methane with top gas recycling in an oxygen blast furnace (BF) is investigated to reduce the emission intensity of steelmaking. Power to gas produces synthetic methane using hydrogen (H2) generated by an electrolyser operated with renewable electricity, and CO2 captured from the BF gas by amine scrubbing supplied with heat from the methanation process. The clean gas from the amine scrubbing is recycled and injected in the BF (via top gas recycling), together with synthetic methane. A parametric analysis is performed to vary the amount of top gas recycled (from 0 kg/tHM to 270 kg/tHM). Based on the results, CO2 equivalent emissions can decrease by 34% using power to gas technology, and by 30% with power to gas and top gas recycling (compared to conventional BFs). Nevertheless, if both integrations are present, additional benefits on the specific energy consumption (12.0 MJ/tHM), and specific cost (130 €/tHM) are achieved, compared to only applying power to gas (17.5 MJ/tHM and 233 €/tHM). In all cases, the downstream thermal energy needs of the steel plant are fulfilled, contrarily to conventional top gas recycling concepts. The main conclusion is that top gas recycling should be considered together with PtG technology, and vice versa, when integrated in blast furnace ironmaking, in order to both abate emissions while supplying downstream energy needs.

Abstract Natural gas processing plants in the Persian Gulf face extreme climatic conditions that constrain their gas turbine (GT) power generation and cooling capacities. However, due to a past history of low hydrocarbon prices, such plants have not fully exploited their waste heat recovery potential to date. The techno-economic performance of a combined cooling, heating and power (CCHP) scheme designed to enhance the energy efficiency of a major natural gas liquids extraction plant in the Persian Gulf is assessed. The trigeneration scheme utilizes double-effect water–lithium bromide absorption refrigeration powered by steam generated from GT exhaust gas waste heat to provide both GT compressor inlet air- and process gas cooling. Part of the generated steam is also used for process gas heating. Thermodynamic modeling reveals that recovery of 82 MW of GT waste heat would provide additional cooling and heating capacities of 75 MW and 24 MW to the plant, respectively, thereby permitting elimination of a 28 MW GT, and existing cooling and heating equipment. GT compressor inlet air cooling alone yields approximately 151 GW h of additional electric power annually, highlighting the effectiveness of absorption refrigeration in meeting compressor inlet air cooling loads throughout the year in the Gulf climate. The overall net annual operating expenditure savings contributed by the CCHP system would average approximately 14.6 million US$ over its lifespan, which corresponds to average yearly savings of 190 MMSCM of natural gas. The CCHP scheme economic payback period is conservatively estimated at 2.7 years based on current utility and domestic gas prices. The net present value of the CCHP system is estimated at 158 million USD, with an internal rate of return of 39%.

Abstract Natural gas processing plants in the Persian Gulf face extreme climatic conditions that constrain their gas turbine (GT) power generation and cooling capacities. However, due to a past history of low hydrocarbon prices, such plants have not fully exploited their waste heat recovery potential to date. The techno-economic performance of a combined cooling, heating and power (CCHP) scheme designed to enhance the energy efficiency of a major natural gas liquids extraction plant in the Persian Gulf is assessed. The trigeneration scheme utilizes double-effect water–lithium bromide absorption refrigeration powered by steam generated from GT exhaust gas waste heat to provide both GT compressor inlet air- and process gas cooling. Part of the generated steam is also used for process gas heating. Thermodynamic modeling reveals that recovery of 82 MW of GT waste heat would provide additional cooling and heating capacities of 75 MW and 24 MW to the plant, respectively, thereby permitting elimination of a 28 MW GT, and existing cooling and heating equipment. GT compressor inlet air cooling alone yields approximately 151 GW h of additional electric power annually, highlighting the effectiveness of absorption refrigeration in meeting compressor inlet air cooling loads throughout the year in the Gulf climate. The overall net annual operating expenditure savings contributed by the CCHP system would average approximately 14.6 million US$ over its lifespan, which corresponds to average yearly savings of 190 MMSCM of natural gas. The CCHP scheme economic payback period is conservatively estimated at 2.7 years based on current utility and domestic gas prices. The net present value of the CCHP system is estimated at 158 million USD, with an internal rate of return of 39%.

Abstract The storage of excess or low-carbon electricity in the form of synthetic gas using power-to-gas technologies is a promising approach to enable high shares of renewables in power generation and reduce the fuel carbon content. However, the efficiency of standalone, low-temperature electrolysis-based power-to-methane (PtM) processes is presently limited. As a way of enhancing the potential of this technology to support the decarbonization of energy systems, this study investigates a high-temperature electrolysis-based PtM process and its integration with oxyfuel combustion to co-generate synthetic methane, heat and power. The system incorporates in-situ heat, oxygen, carbon dioxide (CO2) and water recycling. The energy and exergy-based performance of the compound system and its main structures are investigated using an overpotential-based electrochemical model. Depending on electrolysis operating temperature (800–1000 °C) and pressure (1–10 bar), overall energy and exergy efficiencies range from 75.8% to 79.3% and 64.5% to 67.4%, respectively. In quasi-continuous operation, a 6.4 MWe (AC input) hybrid PtM system would avoid approximately 1.9 GWhe of electricity consumption for oxygen-air separation, and sink 6.6 kt of CO2 from the oxyfuel co-generation plant annually. In parallel, 3.1 MWth of heat could be recovered from the pre-methanation compressor and oxyfuel conversion products for use in external applications. Based on a carbon balance evaluation from initial resource extraction to SNG conversion, the PtM-oxyfuel hybridization investigated could effectively contribute to raise the electricity greenhouse gas (GHG) emission threshold below which SNG could environmentally compete with natural gas, relative to low-temperature electrolysis-based PtM and conventional post-combustion CO2 capture.

Abstract The storage of excess or low-carbon electricity in the form of synthetic gas using power-to-gas technologies is a promising approach to enable high shares of renewables in power generation and reduce the fuel carbon content. However, the efficiency of standalone, low-temperature electrolysis-based power-to-methane (PtM) processes is presently limited. As a way of enhancing the potential of this technology to support the decarbonization of energy systems, this study investigates a high-temperature electrolysis-based PtM process and its integration with oxyfuel combustion to co-generate synthetic methane, heat and power. The system incorporates in-situ heat, oxygen, carbon dioxide (CO2) and water recycling. The energy and exergy-based performance of the compound system and its main structures are investigated using an overpotential-based electrochemical model. Depending on electrolysis operating temperature (800–1000 °C) and pressure (1–10 bar), overall energy and exergy efficiencies range from 75.8% to 79.3% and 64.5% to 67.4%, respectively. In quasi-continuous operation, a 6.4 MWe (AC input) hybrid PtM system would avoid approximately 1.9 GWhe of electricity consumption for oxygen-air separation, and sink 6.6 kt of CO2 from the oxyfuel co-generation plant annually. In parallel, 3.1 MWth of heat could be recovered from the pre-methanation compressor and oxyfuel conversion products for use in external applications. Based on a carbon balance evaluation from initial resource extraction to SNG conversion, the PtM-oxyfuel hybridization investigated could effectively contribute to raise the electricity greenhouse gas (GHG) emission threshold below which SNG could environmentally compete with natural gas, relative to low-temperature electrolysis-based PtM and conventional post-combustion CO2 capture.

In the last years, reduction of CO2 emissions from the steel industry has been of great importance. Carbon capture, oxygen blast furnaces and top gas recycling technologies, among others, have been deeply studied as low carbon solutions. In this paper, a novel integration of carbon capture and power to gas technologies in the steelmaking industry is presented. Green hydrogen via proton exchange membrane (PEM) electrolysis and CO2 via methyldiethanolamine (MDEA) scrubbing from the blast furnace gas (BFG) are used to produce synthetic natural gas in an isothermal fixed bed methanation plant. The latter gas is injected into the blast furnace, closing a carbon loop and reducing coal consumption. The oxygen by-produced in the electrolyser covers the entire oxygen demand of the steelmaking plant and avoids the need for an air separation unit (ASU). The novelty of this work relies on the variation of the oxygen enrichment and its temperature in the hot blast, and how it influences the power to gas integration concept. This power to gas integration is compared with a conventional BF-BOF plant from a technical, economic, energy and environmental point of view. Both plant process configurations were implemented in Aspen Plus simulations, assessing the fossil fuel demand, energy penalty, cost and CO2 emissions. Emission reduction up to 34% can be achieved with power to gas integration, with an energy penalty of 17 MJ/tHM and a cost of 352 €/tCO2.

In the last years, reduction of CO2 emissions from the steel industry has been of great importance. Carbon capture, oxygen blast furnaces and top gas recycling technologies, among others, have been deeply studied as low carbon solutions. In this paper, a novel integration of carbon capture and power to gas technologies in the steelmaking industry is presented. Green hydrogen via proton exchange membrane (PEM) electrolysis and CO2 via methyldiethanolamine (MDEA) scrubbing from the blast furnace gas (BFG) are used to produce synthetic natural gas in an isothermal fixed bed methanation plant. The latter gas is injected into the blast furnace, closing a carbon loop and reducing coal consumption. The oxygen by-produced in the electrolyser covers the entire oxygen demand of the steelmaking plant and avoids the need for an air separation unit (ASU). The novelty of this work relies on the variation of the oxygen enrichment and its temperature in the hot blast, and how it influences the power to gas integration concept. This power to gas integration is compared with a conventional BF-BOF plant from a technical, economic, energy and environmental point of view. Both plant process configurations were implemented in Aspen Plus simulations, assessing the fossil fuel demand, energy penalty, cost and CO2 emissions. Emission reduction up to 34% can be achieved with power to gas integration, with an energy penalty of 17 MJ/tHM and a cost of 352 €/tCO2.