Academic literature on the topic 'LCOH (Levelized Cost of Hydrogen)'

The article focused on investigation of cost efficiency of hydrogen production via water electrolysis in Russia up to 2030. Different non-carbon generation technologies were assumed as input sources for electrolysis, namely wind, solar, hydro and nuclear power plants. Analysis is based on levelized cost of hydrogen (LCOH) framework incorporating all cost related to electrolysis (capital cost, operation & maintenance, electricity price, etc.). Additionally, we estimated LCOH sensitivity to some techno-economic parameters – cost of capital, capital expenses and capacity factor of different power supply sources.

This study investigates the techno-economic feasibility of an off-grid integrated solar/wind/hydrokinetic plant to co-generate electricity and hydrogen for a remote micro-community. In addition to the techno-economic viability assessment of the proposed system via HOMER (hybrid optimization of multiple energy resources), a sensitivity analysis is conducted to ascertain the impact of ±10% fluctuations in wind speed, solar radiation, temperature, and water velocity on annual electric production, unmet electricity load, LCOE (levelized cost of electricity), and NPC (net present cost). For this, a far-off village with 15 households is selected as the case study. The results reveal that the NPC, LCOE, and LCOH (levelized cost of hydrogen) of the system are equal to $333,074, 0.1155 $/kWh, and 4.59 $/kg, respectively. Technical analysis indicates that the PV system with the rated capacity of 40 kW accounts for 43.7% of total electricity generation. This portion for the wind turbine and the hydrokinetic turbine with nominal capacities of 10 kW and 20 kW equates to 23.6% and 32.6%, respectively. Finally, the results of sensitivity assessment show that among the four variables only a +10% fluctuation in water velocity causes a 20% decline in NPC and LCOE.

Global trade of green hydrogen will probably become a vital factor in reaching climate neutrality. The sunbelt of the Earth has a great potential for large-scale hydrogen production. One promising pathway to solar hydrogen is to use economically priced electricity from photovoltaics (PV) for electrochemical water splitting. However, storing electricity with batteries is still expensive and without storage only a small operating capacity of electrolyser systems can be reached. Combining PV with concentrated solar power (CSP) and thermal energy storage (TES) seems a good pathway to reach more electrolyser full load hours and thereby lower levelized costs of hydrogen (LCOH). This work introduces an energy system model for finding cost-optimal designs of such PV/CSP hybrid hydrogen production plants based on a global optimization algorithm. The model includes an operational strategy which improves the interplay between PV and CSP part, allowing also to store PV surplus electricity as heat. An exemplary study for stand-alone hydrogen production with an alkaline electrolyser (AEL) system is carried out. Three different locations with different solar resources are considered, regarding the total installed costs (TIC) to obtain realistic LCOH values. The study shows that a combination of PV and CSP is an auspicious concept for large-scale solar hydrogen production, leading to lower costs than using one of the technologies on its own. For today’s PV and CSP costs, minimum levelized costs of hydrogen of 4.04 USD/kg were determined for a plant located in Ouarzazate (Morocco). Considering the foreseen decrease in PV and CSP costs until 2030, cuts the LCOH to 3.09 USD/kg while still a combination of PV and CSP is the most economic system.

Hydrogen production using renewable power is becoming an essential pillar for future sustainable energy sector development worldwide. The Sultanate of Oman is presently integrating renewable power generations with a large share of solar photovoltaic (PV) systems. The possibility of using the solar potential of the Sultanate can increase energy security and contribute to the development of the sustainable energy sector not only for the country but also for the international community. This study presents the hydrogen production potential using solar resources available in the Sultanate. About 15 locations throughout the Sultanate are considered to assess the hydrogen production opportunity using a solar PV system. A rank of merit order of the locations for producing hydrogen is identified. It reveals that Thumrait and Marmul are the most suitable locations, whereas Sur is the least qualified. This study also assesses the economic feasibility of hydrogen production, which shows that the levelized cost of hydrogen (LCOH) in the most suitable site, Thumrait, is 6.31 USD/kg. The LCOH in the least convenient location, Sur, is 7.32 USD/kg. Finally, a sensitivity analysis is performed to reveal the most significant influential factor affecting the future’s green hydrogen production cost. The findings indicate that green hydrogen production using solar power in the Sultanate is promising, and the LCOH is consistent with other studies worldwide.

The results of a techno-economic model of distributed wind-hydrogen systems (WHS) located at each existing wind farm on the island of Ireland are presented in this paper. Hydrogen is produced by water electrolysis from wind energy and backed up by grid electricity, compressed before temporarily stored, then transported to the nearest injection location on the natural gas network. The model employs a novel correlation-based approach to select an optimum electrolyser capacity that generates a minimum levelised cost of hydrogen production (LCOH) for each WHS. Three scenarios of electrolyser operation are studied: (1) curtailed wind, (2) available wind, and (3) full capacity operations. Additionally, two sets of input parameters are used: (1) current and (2) future techno-economic parameters. Additionally, two electricity prices are considered: (1) low and (2) high prices. A closest facility algorithm in a geographic information system (GIS) package identifies the shortest routes from each WHS to its nearest injection point. By using current parameters, results show that small wind farms are not suitable to run electrolysers under available wind operation. They must be run at full capacity to achieve sufficiently low LCOH. At full capacity, the future average LCOH is 6–8 €/kg with total hydrogen production capacity of 49 kilotonnes per year, or equivalent to nearly 3% of Irish natural gas consumption. This potential will increase significantly due to the projected expansion of installed wind capacity in Ireland from 5 GW in 2020 to 10 GW in 2030.

Ammonia is a particularly promising hydrogen carrier due to its relatively low cost, high energy density, its liquid storage and to its production from renewable sources. Thus, in recent years, great attention is devoted to this fuel for realizing next generation refueling stations according to a carbon-free energy economy. In this paper a distributed onsite refueling station (200 kg/day of hydrogen filling 700-bar HFCEVs (Hybrid Fuel Cell Electric Vehicles) with about 5 kg of hydrogen in 5 min), based on ammonia feeding, is studied from the energy and economic point of views. The station is designed with a modular configuration consisting of more sections: i) the hydrogen production section, ii) the electric energy supplier section, iii) the compression and storage section and the refrigeration/dispenser section. The core of the station is the hydrogen production section that is based on an ammonia cracking reactor and its auxiliaries; the electric energy demand necessary for the station operation (i.e. the hydrogen compression and refrigeration) is satisfied by a PEMFC (Proton-Exchange Membrane Fuel Cell) power module. Energy performance, according to the hydrogen daily demand, has been evaluated and the estimation of the levelized cost of hydrogen (LCOH) has been carried out in order to establish the cost of the hydrogen at the pump that can assure the feasibility of this novel refueling station.

At the present stage of electric power industry development, special attention is being paid to the development and research of new efficient energy sources. The use of hydrogen fuel cells is promising for remote autonomous power supply systems. The authors of the paper have developed the structure and determined the optimal composition of a hybrid generation system based on hydrogen fuel cells and battery storage and have conducted studies of its operating modes and for remote consumers’ power supply efficiency. A simulation of the electromagnetic processes was carried out to check the operability of the proposed hybrid generation system structure. The simulation results confirmed the operability of the structure under consideration, the calculation of its parameters reliability and the high quality of the output voltage. The electricity cost of a hybrid generation system was estimated according to the LCOE (levelized cost of energy) indicator, its value being 1.17 USD/kWh. The factors influencing the electricity cost of a hydrogen generation system have been determined and ways for reducing its cost identified.

Renewable energy has become very popular in recent years. The amount of renewable generation has increased in both grid-connected and stand-alone systems. This is because it can provide clean energy in a cost-effective and environmentally friendly fashion. Among all varieties, photovoltaic (PV) is the ultimate rising star. Integration of other technologies with solar is enhancing the efficiency and reliability of the system. In this paper a fuel cell–solar photovoltaic (FC-PV)-based hybrid energy system has been proposed to meet the electrical load demand of a small community center in India. The system is developed with PV panels, fuel cell, an electrolyzer and hydrogen storage tank. Detailed mathematical modeling of this system as well as its operation algorithm have been presented. Furthermore, cost optimization has been performed to determine ratings of PV and Hydrogen system components. The objective is to minimize the levelized cost of electricity (LCOE) of this standalone system. This optimization is performed in HOMER software as well as another tool using an artificial bee colony (ABC). The results obtained by both methods have been compared in terms of cost effectiveness. It is evident from the results that for a 68 MWh/yr of electricity demand is met by the 129 kW Solar PV, 15 kW Fuel cell along with a 34 kW electrolyzer and a 20 kg hydrogen tank with a LPSP of 0.053%. The LCOE is found to be in 0.228 $/kWh. Results also show that use of more sophisticated algorithms such as ABC yields more optimized solutions than package programs, such as HOMER. Finally, operational details for FC-PV hybrid system using IEC 61850 inter-operable communication is presented. IEC 61850 information models for FC, electrolyzer, hydrogen tank were developed and relevent IEC 61850 message exchanges for energy management in FC-PV hybrid system are demonstrated.

Diesel generators are currently used as an off-grid solution for backup power, but this causes CO2 and GHG emissions, noise emissions, and the negative effects of the volatile diesel market influencing operating costs. Green hydrogen production, by means of water electrolysis, has been proposed as a feasible solution to fill the gaps between demand and production, the main handicaps of using exclusively renewable energy in isolated applications. This manuscript presents a business case of an off-grid hydrogen production by electrolysis applied to the electrification of isolated sites. This study is part of the European Ely4off project (n° 700359). Under certain techno-economic hypothesis, four different system configurations supplied exclusively by photovoltaic are compared to find the optimal Levelized Cost of Electricity (LCoE): photovoltaic-batteries, photovoltaic-hydrogen-batteries, photovoltaic-diesel generator, and diesel generator; the influence of the location and the impact of different consumptions profiles is explored. Several simulations developed through specific modeling software are carried out and discussed. The main finding is that diesel-based systems still allow lower costs than any other solution, although hydrogen-based solutions can compete with other technologies under certain conditions.

In order to reduce the load demand of buildings in Japan, this study proposes a grid-tied hybrid solar–wind–hydrogen system that is equipped with a maximum power point tracking (MPPT) system, using a fuzzy logic control (FLC) algorithm. Compared with the existing MPPTs, the proposed MPPT provides rapid power control with small oscillations. The dynamic simulation of the proposed hybrid renewable energy system (HRES) was performed in MATLAB-Simulink, and the model results were validated using an experimental setup installed in the Chikushi campus, Kyushu University, Japan. The techno-economic analysis (TEA) of the proposed system was performed to estimate the optimal configuration of the proposed HRES, subject to satisfying the required annual load in the Chikushi campus. The results revealed a potential of 2% surplus power generation from the proposed HRES, using the FLC-based MPPT system, which can guarantee a lower levelized cost of electricity (LOCE) for the HRES and significant savings of 2.17 million yen per year. The TEA results show that reducing the cost of the solar system market will lead to a reduction in LCOE of the HRES in 2030.

The exigent need to address climate change and its adverse effects is felt all around the world. As pioneers in tackling carbon emissions, the European Union continue to be head and shoulders above other continents by implementing policies and keeping a tab on its carbon dependence and emissions. However, being one of the largest importers of Natural Gas in the world, the EU remains dependent on a fossil fuel to meet its demands.  The aim of the research is to investigate the barriers and constraints in the EU policies and framework that affects the natural gas decarbonization and to investigate the levelized cost of hydrogen production (LCOH) that would be used to decarbonize the natural gas sector. Thus a comprehensive study, based on existing academic and scientific literature, EU policies, framework and regulations pertinent to Natural gas and a techno economic analysis of possible substitution of natural gas with Hydrogen, is performed. The motivation behind choosing hydrogen is based on various research studies that indicate the importance and ability to replace to natural gas. In addition, Portugal provides a great environment for cheap green hydrogen production and thus chosen as the main region of evaluation.  The study evaluates the current framework based on a SWOT ((Strength, Weakness, and Opportunities & Weakness) analysis, which includes a PESTEL (Political, Economic, Social, Technological, Environmental & Legal) macroeconomic factor assessment and an expert elicitation. The levelized cost of hydrogen is calculated for blue (SMR - Steam Methane Reforming with natural gas as the feedstock) and green hydrogen (Electrolyzer with electricity from grid, solar and wind sources). The costs were specific to Portuguese conditions and for the years 2020, 2030 and 2050 based on availability of data and the alignment with the National Energy and Climate Plan (NECP) and the climate action framework 2050. The sizes of Electrolyzers are based on the current Market capacities while SMR is capped at 300MW. The thesis only considers production of hydrogen. Transmission, distribution and storage of hydrogen are beyond the scope of the analysis.  Results show that the barriers are mainly related to costs competitiveness, amendments in rules/regulations, provisions of incentives, and constraints in the creation of market demand for low carbon gases. Ensuring energy security and supply while being economically feasible demands immediate amendments to the regulations and policies such as incentivizing supply, creating a demand for low carbon gases and taxation on carbon.  Considering the LCOH, the cheapest production costs continue to be dominated by blue hydrogen (1.33 € per kg of H2) in comparison to green hydrogen (4.27 and 3.68 € per kg of H2) from grid electricity and solar power respectively. The sensitivity analysis shows the importance of investments costs and the efficiency in case of electrolyzers and the carbon tax in the case of SMR. With improvements in electrolyzer technologies and increased carbon tax, the uptake of green hydrogen would be easier, ensuring a fair yet competitive gas market.
Det starka behovet av att ta itu med klimatförändringarna och deras negativa effekter är omfattande världen över. Den europeiska unionen utgör en pionjär när det gäller att såväl hantera sina koldioxidberoende och utsläpp som att implementera reglerande miljöpolitik, och framstår därmed som överlägsen andra stater och organisationer i detta hänseende. Unionen är emellertid fortfarande mycket beroende av fossilt bränsle för att uppfylla sina energibehov, och kvarstår därför som en av världens största importörer av naturgas.  Syftet med denna forskningsavhandling är att undersöka befintliga hinder och restriktioner i EU: s politiska ramverk som medför konsekvenser avkolningen av naturgas, samt att undersöka de utjämnande kostnaderna för väteproduktion (LCOH) som kan användas för att avkolna naturgassektorn. Därmed utförs en omfattande studie baserad på befintlig akademisk och vetenskaplig litteratur, EU: s politiska ramverk och stadgar som är relevanta för naturgasindustrin. Dessutom genomförs en teknisk-ekonomisk analys av eventuella ersättningar av naturgas med väte. Valet av väte som forskningsobjekt motiveras olika forskningsstudier som indikerar vikten och förmågan att ersätta till naturgas. Till sist berör studien Portugal. som tillhandahåller en lämplig miljö för billig och grön vätgasproduktion. Av denna anledning är Portugal utvalt som den viktigaste utvärderingsregionen.  Studien utvärderar det nuvarande ramverket baserat på en SWOT-analys ((Strength, Weakness, and Opportunities & Weakness), som inkluderar en PESTEL (Political, Economical, Social, Technological, Environmental och Legal) makroekonomisk faktoranalys och elicitering. Den utjömnade vätekostnaden beräknades i blått (SMR - Ångmetanreformering med naturgas som råvara) och grönt väte (elektrolyser med el från elnät, sol och vindkällor). Kostnaderna var specifika för de portugisiska förhållandena under åren 2020, 2030 och 2050 baserat på tillgänglighet av data samt anpassningen till den nationella energi- och klimatplanen (NECP) och klimatåtgärdsramen 2050. Storleken på elektrolyserar baseras på den nuvarande marknadskapaciteten medan SMR är begränsad till 300 MW. Avhandlingen tar endast hänsyn till produktionen av vätgas. Transmission, distribution och lagring av väte ligger utanför analysens räckvidd.  Resultaten visar att hindren är främst relaterade till kostnadskonkurrens, förändringar i stadgar och bestämmelser, incitament och begränsningar i formerandet av efterfrågan på koldioxidsnåla gaser på marknaden. Att säkerställa energiförsörjning och tillgång på ett ekonomiskt hållbart sätt kräver omedelbara ändringar av reglerna och politiken, såsom att stimulera utbudet, att skapa en efterfrågan på koldioxidsnåla gaser och genom att beskatta kol.  När det gäller LCOH dominerar blåväte beträffande produktionskostnaderna (1,33 € per kg H2) jämfört med grönt väte (4,27 respektive 3,68 € per kg H2) från elnät respektive solenergi. Osäkerhetsanalysen visar vikten av investeringskostnader och effektiviteten vid elektrolysörer och koldioxidskatten för SMR. Med förbättringar av elektrolys-tekniken och ökad koldioxidskatt skulle upptagningen av grön vätgas vara enklare och säkerställa en rättvis men konkurrenskraftig gasmarknad.

Alltmer intermittent elkraft byggs idag i Sverige för att öka andelen förnybar el i energisystemet. Detta leder till mer ojämn elproduktion, vilket skapar problem i form av mer volatila och oförutsägbara elpriser. Ett sätt att dämpa effekten av den ökande intermittenta kraften är att använda förnybar vätgasproduktion som lastutjämning. På detta sätt kan vätgasen potentiellt bli en viktig del i den fossilfria energimixen. Att använda vätgas som energilager i en Power-to-Power-applikation (P2P) möjliggör även utnyttjandet av prisarbitrage på elmarknaden. Ett ökat klimatfokus har återuppväckt intresset för hur vätgasproduktion kan göras lönsamt. Några tecken på att satsningar sker är att flera länder satsar stora pengar på vätgastekniker och infrastruktur, där flertalet samarbeten över nationella gränser har etablerats.Denna studie syftar till att undersöka de tekno-ekonomiska förutsättningarna för produktion av förnybar vätgas där lönsamheten av arbitragehandel på elmarknaden Elspot bedöms. Detta innefattar en gedigen granskning av kommersiella tekniker lämpade för Linköpings energisystem, däribland elektrolys, ångreformering och bränslecell. Tre fall konstruerades med olika uppsättningar av ingående komponenter. Sedan utfördes en driftoptimering som tog fram övre och undre prisgränser för produktion respektive konvertering av vätgas mot spotpriset. Optimeringsverktyget Problemlösaren i Excel användes för att få fram dessa gränser. Visual Basic (VBA) användes sedan för att genomföra en lagersimulering som visualiserar lagersaldot för alla årets timmar. För att få fram kostnaden för varje kilogram producerad vätgas användes nuvärdesberäkningen Levelised Cost of Energy (LCOE), vilket även underlättade jämförelsen av de tre fallen. Vilka effekter i form av växthusgasutsläpp de olika anläggningarna medför utvärderades också genom beräkningssättet konsekvensanalys. Där jämfördes effekten i form av nettoutsläpp i koldioxidekvivalenter för integrering av respektive anläggning. Resultaten visar på att det finns kommersiella tekniker som kan integreras med det befintliga energisystemet på ett resurseffektivt sätt, däremot är de ekonomiska förutsättningarna inte lika bra och P2P-lösningarna är idag långt ifrån lönsamma. Anledningen tros vara en kombination av otillräckliga elprisfluktuationer samt låg total systemverkningsgrad (som högst 14%) för samtliga konstruerade fall. De årliga intäkterna från elförsäljningen motsvarar cirka 1 procent av de årliga kostnaderna för anläggningen, och LCOE landade på cirka 1500 kronor. Resultaten från investeringskalkyleringen visar på att en högre utnyttjandegrad leder till en lägre LCOE. Lagersimuleringen visar på att säsongslagring krävs för denna typ av anläggning då fluktuationerna inte är tillräcklig stora på en daglig, veckovis eller månatlig basis. Känslighetsanalys på LCOE och driftoptimeringen visar inte heller på lönsamhetsmöjligheter i P2P-fallen även vid gynnsamma justeringar på parametrarna investeringskostnad, elpris och verkningsgrad. Ur ett klimatperspektiv visar samtliga fall, med ett undantag, på en minskade växthusgasutsläpp i regionen.  Slutsatsen som dras av resultaten från fallstudien är att, trots goda tekniska förutsättningar och positiv inverkan på lokala växthusgasutsläpp, kan en P2P-applikation med vätgaslagring inte göras lönsam i en svensk kontext inom en nära framtid. Däremot visar ett Power-to-Gas-fall potential för lönsamhet, då dess investeringskostnad är mindre samt att systemverkningsgraden är högre.
More and more intermittent electric power is being built in Sweden today to increase the share of renewable electricity in the energy system. This leads to more uneven electricity generation, which creates problems in terms of more volatile and unpredictable electricity prices. One way to dampen the effect of the increasing intermittent power is to use renewable hydrogen production as load shedding. In this way, the hydrogen gas can potentially become an important part of the fossil-free energy mix. Using hydrogen as energy storage in a Power-to-Power application (P2P) also enables the use of price arbitrage in the electricity market. An increased climate focus has rekindled interest in how hydrogen production can be made profitable. Some signs that investments are taking place are that several countries are investing big money on hydrogen technologies and infrastructure, and collaborations across national borders have been established. This study aims to investigate the techno-economic prerequisites for renewable hydrogen production where the profitability of arbitrage on the Elspot market is explored. This comprises a thorough investigation of commercial technologies suited for Linköping’s energy system. Three cases where constructed with different component constellations. Then the operational strategy was optimised which generated a lower and upper price limit for production and conversion of hydrogen with input price data from Elspot. The optimisation tool in Excel was used in order to obtain these price limits. Visual Basic (VBA) was then used for storage simulation in order to get a perception of the storage development through all the hours of the year. The cost of every kilogram of hydrogen produced was then calculated through Levelized Cost of Energy (LCOE), which made the comparison of the three cases easier. The resulting greenhouse gas emissions when integrating the facilities in each case were also evaluated with a so-called impact analysis. The effect was compared in net emissions in carbon dioxide equivalents for an integration of each facility.     The results show that there are commercial technologies that can be integrated with the existing energy system in a resource efficient manner, whereas the economic prerequisites are not as good, where today’s Power-to-Power (P2P) solutions are not profitable. The reason seems to be the combination of insufficient spot price fluctuations and a low system efficiency (14% at best) for each case. The annual revenues correspond to 1 percent of the annual costs and that LCOE lands at about 1500 SEK. A higher utilization percentage of the plant shows a lower LCOE in the investment calculation. The storage simulation indicates that a seasonal storage is needed for this type of facility because of that the spot price fluctuations are not big enough on a daily, weekly or monthly basis. The sensitivity analysis made on the investment calculation and operational strategy also shows that there is no profitability in the P2P cases where parameters regarding investment cost, efficiency and electricity price were set optimistically. The Power-to-Gas case on the other hand shows potential for profitability, all because of lower total investment costs and higher efficiency. All cases except the case with steam methane reforming shows reductions in greenhouse gas emissions when integrated in the regional energy system.   The conclusion that can be drawn from the results in the case study is that, in spite of good technological prerequisites and a positive effect on local greenhouse gas emissions, a P2P-application with hydrogen storage cannot be made profitable in a Swedish context in the near future. However, a Power-to-Gas case shows potential for profitability because of its lesser investment cost and that the system efficiency is higher.

There has recently been an increased interest in hydrogen, both as a solution for seasonal energy storage but also for implementations in various industries and as fuel for vehicles. The transition to a society less dependent on fossil fuels highlights the need for new solutions where hydrogen is predicted to play a key role. This project aims to investigate technical and economic outcomes of different strategies for production and storage of hydrogen based on hydrogen demand and source of electricity. This is done by simulating the operation of different systems over a year, mapping the storage level, the source of electricity, and calculating the levelized cost of hydrogen (LCOH). The study examines two main cases. The first case is a system integrated with offshore wind power for production of hydrogen to fuel the operations in the industrial port Gävle Hamn. The second case examines a system for independent refueling stations where two locations with different electricity prices and traffic flows are analyzed. Factors such as demand, electricity prices, and component costs are investigated through simulating cases as well as a sensitivity analysis. Future potential sources of income are also analyzed and discussed. The results show that using an alkaline electrolyzer (AEL) achieves the lowest LCOH while PEM electrolyzer is more flexible in its operation which enables the system to utilize more electricity from the offshore wind power. When the cost of wind electricity exceeds the average electricity price on the grid, a higher share of wind electricity relative to electricity from the grid being utilized in the production results in a higher LCOH. The optimal design of the storage depends on the demand, where using vessels above ground is the most beneficial option for smaller systems and larger systems benefit financially from using a lined rock cavern (LRC). Hence, the optimal design of a system depends on the demand, electricity source, and ultimately on the purpose of the system. The results show great potential for future implementation of hydrogen systems integrated with wind power. Considering the increased share of wind electricity in the energy system and the expected growth of the hydrogen market, these are results worth acknowledging in future projects.

Abstract A family of “flow-through” turboexpander-generators (TEGs) has been developed by Calnetix Technologies for hydrogen and natural gas pressure letdown applications. A flow-through TEG includes an axial expansion turbine and can be installed directly between two flanges of an existing pipeline. TEGs can be used to generate power throughout the hydrogen and natural gas transmission infrastructure using existing pressure differentials wherever a Joule-Thomson valve is located. These can be upstream, at terminal stations, and downstream, at governor stations. The expander drives a synchronous permanent magnet high-speed generator supported by active magnetic bearings. This paper describes the innovative axial flow-through system architecture, including the use of process gas for cooling the generator rotor and stator. The primary focus of the paper is the economic analysis of the application. Various TEG subsystem design choices and their impact on cost are discussed, including the generator, bearing, expander wheel, seal, and touchdown bearing resilient mount designs. A payback analysis shows that the natural gas TEG has a payback of 2.1 years when a heat exchanger is required for preheating the gas and 1.9 years when waste heat can be used. The hydrogen TEG has a payback of 2.0 years, and does not require external preheating. Finally, a comparison of this technology with other clean energy solutions is presented, using the Levelized Cost of Electricity (LCOE) formulation. The analysis confirms that the LCOE of the expander-generator ($0.40 per megawatt-hour) compares favorably with other types of conventional and renewable energy technologies on a cost basis.

Abstract Energies may be described as brown, blue or green. Brown energies are CO2-emitting fossil fuels. Blue energies employ carbon capture and storage (CCS) technologies to remove the emitted CO2 from brown energies. Green energies are zero or low CO2-emitting renewable energies. Likewise, energy carriers such as electricity and hydrogen may be described as brown, blue or green if they are produced from brown, blue or green energy, respectively. The transition from a high carbon intensity to a low carbon intensity economy will require the decarbonization of three major sectors: power, transport and industry. By analyzing the CO2 intensity and levelized cost of energy (LCOE) of energy and energy carriers of different colors, we show that renewable energies are best used in replacing fossil fuels in the power sector where it has the most impact in reducing CO2 emission. This will consume the majority of new additions to renewable energies in the near to medium future. Consequently, the decarbonation of the transport and industry sectors must begin with the use of blue electricity, blue fossil fuels and blue hydrogen. To achieve this, implementation of large-scale CCS projects will be necessary, especially outside of USA and northern Europe. However, this will not happen until significant financial incentives in the form of carbon tax or carbon credit becomes available from national governments. Furthermore, private-public partnership and intergovernmental cooperation will be needed to implement these CCS projects.

Abstract A low-carbon world needs a replacement for natural gas-fired power to provide variable heat and electricity. The coupling of simple or combined cycle gas turbines (CCGTs) with advanced electrically-heated thermal energy storage (E-TES) systems is an alternative approach to energy storage with cost advantages over batteries or hydrogen production. CCGTs with E-TES may use stored low-value electricity to run the power cycle in place of fossil fuels. This (1) saves money for the power plants by allowing them to switch heat sources based on price, and (2) reduces carbon emissions by making use of otherwise curtailed renewable energy. The development of electrically conductive firebricks enables temperatures approaching 2000°C, hotter than existing E-TES options, sufficient to run CCGTs. Levelized cost of storage (LCOS) calculations show that the use of CCGTs with novel E-TES increases the cost of energy by less than a factor of 2, compared to a factor of 9 increase when using lithium-ion batteries. Unlike batteries, the CCGT with E-TES, provides assured generating capacity by normal operation of the gas turbine. A case study of CCGT coupled with E-TES is included based on 2019 electricity prices in Southern California, which showed an 18% reduction in fuel consumption and $11M savings based purely on the arbitrage case. The arbitrage case is expected to improve dramatically over the decade as deployment of renewable energy in California increases.

Abstract A numerical model of the CentRec® receiver has been developed and validated using the measurement data collected during the experimental test campaign of the centrifugal particle system at the solar tower Jülich. The model has been used to calculate the thermo-optical efficiency of a scaled-up 20 MWth receiver for various receiver geometries. A cost function has been deduced and was used to perform a technoeconomic optimization on an LCOH (levelized cost of heat) basis of the CentRec® receiver concept. Attractive LCOH as low as 0.0209 €/kWhth for a system with thermal storage, or as low as 0.0150 €/kWhth for the LCOH without storage, are predicted. This study has shown that the optimal configuration from an LCOH perspective for a 20 MWth centrifugal particle receiver reaches specific receiver costs of 35 €/kWth. Hereby the costs of the receiver can be reduced by 60 % compared to the original configuration.

The potential for highly efficient and cost competitive solar energy collection at high temperatures drives the actual research and development activities for particle tower systems. One promising concept for particle receivers is the falling particle receiver. This paper is related to a particle receiver, in which falling ceramic particles form a particle curtain, which absorbs the concentrated solar radiation. Complex operation strategies will result in higher receiver costs, for both investment and operation. The objective of this paper is to assess the influence of the simultaneous variation of receiver costs and efficiency characteristics on levelized cost of heat (LCOH) and on levelized cost of electricity (LCOE). Applying cost assumptions for the particle receiver and the particle transport system, the LCOE are estimated and compared for each considered concept. The power level of the compared concepts is 125 MWel output at design point. The sensitivity of the results on the specific cost assumptions is analyzed. No detailed evaluation is done for the thermal storage, but comparable storage utilization and costs are assumed for all cases.

After significant interest in the 1970s, but relatively few deployments, the use of concentrating solar collectors for thermal applications, including enhanced oil recovery, desalination, and industrial process heat (IPH), is again increasing in global interest. In particular, recent advances in collector design and manufacturing have led to reduced cost per square meter of aperture area. In this study, analysis of a modern parabolic trough that is suited for use in small solar IPH (SIPH) applications predicts that the installed solar field cost can be as low as $170/m2. A slightly higher cost of $200/m2 is estimated for facilities typical of a SIPH plant size. Full project costs will include additional costs for contingency, piping and heat exchanger interface, and project indirect costs. The cost for solar-generated heat by SIPH is quantified by defining the levelized cost of heat (LCOH). California offers a favorable environment for SIPH given its good insolation, gas prices typically higher than the national average, and policies promoting solar-thermal deployment. Given historically low gas prices, competing with natural gas remains the primary challenge to deployment. However, this study finds that the solar LCOH for many regions in California is lower than the LCOH from natural gas, using a representative installed solar hardware price and the average price for industrial natural gas in California. Lastly, modification are in progress to the parabolic trough model within NREL’s System Advisor Model (SAM) to allow users to more easily predict performance for these steam-generation applications.

The levelized costs of delivered energy from the leading technologies for grid-scale energy storage are calculated using a model that considers likely number of cycles per year, application-specific expected lifetime, discount rate, duty cycle, and likely trends in the markets. The expected capital costs of the various options evaluated — pumped hydrostorage, underground pumped hydrostorage (UPHS), hydrogen fuel cells, carbon-lead-acid batteries, advanced adiabatic compressed air energy storage (AA-CAES), lead-acid batteries, lithium-ion batteries, flywheels, sodium sulfur batteries, ultra capacitors, and superconducting magnetic energy storage (SMES) — are based on recent installation cost data to the extent possible. The marginal value of the delivered stored energy is analyzed using recent grid-energy prices from regions of high wind-energy penetration. Grid-scale energy storage is expected to lead to significant reductions in greenhouse gas (GHG) emissions only in regions where the off-peak energy is very clean. These areas will be characterized by a high level of wind energy with cheap off-peak and peak prices. At the expected price differentials, the only conventional options expected to be commercially viable in most cases are hydro storage, especially via dam up-rating, and UPHS. The market value of energy storage for short periods of time (under a few hours) is expected to be minimal for grid-scale purposes. Only low-cost daily storage is easily justified both from an economic and environmental perspective.

Each combination of technologies necessary to produce, deliver, and distribute hydrogen for transportation use has a corresponding levelized cost, energy requirement, and greenhouse gas emission profile depending upon the technologies’ efficiencies and costs. Understanding the technical status, potential, and tradeoffs is necessary to properly allocate research and development (R&D) funding. In this paper, levelized delivered hydrogen costs, pathway energy use, and well-to-wheels (WTW) energy use and emissions are reported for multiple hydrogen production, delivery, and distribution pathways. Technologies analyzed include both central and distributed reforming of natural gas and electrolysis of water, and central hydrogen production from biomass and coal. Delivery options analyzed include trucks carrying liquid hydrogen and pipelines carrying gaseous hydrogen. Projected costs, energy use, and emissions for current technologies (technology that has been developed to at least the bench-scale, extrapolated to commercial-scale) are reported. Results compare favorably with those for gasoline, diesel, and E85 used in current internal combustion engine (ICE) vehicles, gasoline hybrid electric vehicles (HEVs), and flexible fuel vehicles. Sensitivities of pathway cost, pathway energy use, WTW energy use, and WTW emissions to important primary parameters were examined as an aid in understanding the benefits of various options. Sensitivity studies on production process energy efficiency, total production process capital investment, feed stock cost, production facility operating capacity, electricity grid mix, hydrogen vehicle market penetration, distance from the hydrogen production facility to city gate, and other parameters are reported. The Hydrogen Macro-System Model (MSM) was used for this analysis. The MSM estimates the cost, energy use, and emissions trade offs of various hydrogen production, delivery, and distribution pathways under consideration. The MSM links the H2A Production Model, the Hydrogen Delivery Scenario Analysis Model (HDSAM), and the Greenhouse Gas, Regulated Emission, and Energy for Transportation (GREET) Model. The MSM utilizes the capabilities of each component model and ensures the use of consistent parameters between the models to enable analysis of full hydrogen production, delivery, and distribution pathways. To better understand spatial aspects of hydrogen pathways, the MSM is linked to the Hydrogen Demand and Resource Analysis Tool (HyDRA). The MSM is available to the public and enables users to analyze the pathways and complete sensitivity analyses.

Abstract Kuwait’s oil reserves include approximately 13 bn barrels of heavy oil, primarily located in the northern region of the country. The Lower Fars (LF) heavy oil development project aims to extract heavy oil from the Ratqa oil field. The US$7 bn project is being developed in phases, with the first phase expected to start in 2019 with a production rate of 60,000 Barrel of Oil Per Day (BOPD). This amount is planned to ramp up to 270,000 BOPD by 2030. The steam required for the Enhanced Heavy Oil Recovery (EHOR) process can be either generated by using conventional fuels or renewable energy resources, such as solar energy. The amount of steam required to recover a certain quantity of heavy oil depends on the value of Steam to Oil Ratio (SOR). The aim of this work was to determine the specifications of a parabolic trough collector field required to produce steam with the right properties to recover 270,000 BOPD from Lower Fars reservoir. The Industrial Process Heat (IPH) model of the System Advisor Model (SAM) software, developed by the National Renewable Energy Laboratory (NREL), was used for this purpose. The capital cost and the running cost of the project, as well as the Levelized Cost of Heat (LCOH), were also determined. The simulation was implemented on EuroTrough ET150 trough collectors and Schott PTR 70 receiving tubes. Different plant designs with different types of heat transfer fluids (HTF) including Therminol VP-1, Therminol 59, Therminol 66, Dowtherm Q, Dowtherm RP, and Caloria HT43 have been investigated.

Abstract Hydrogen-fired gas turbines have the potential to play an important role in future CO2-neutral energy and industry sectors. A prerequisite for the operation of hydrogen-fired gas turbines is the availability of sufficient quantities of hydrogen. The combination of electrolysis and renewable power generation is currently considered the most relevant pathway for the large-scale production of CO2-neutral hydrogen. Regarding the fuel supply of hydrogen-fired gas turbines, this pathway is associated with various technical and economic challenges. This applies in particular to configurations in which electrolyzers and hydrogen storage capacities are installed directly at gas turbine sites to avoid hydrogen transport. Considering an exemplary system configuration, the present study extends prior model-based investigations by focusing on the economic viability of the on-site fuel supply of hydrogen-fired gas turbines. The impact of various design parameters and operational strategies is analyzed using the Levelized Cost of Hydrogen as the main economic indicator. The study reveals that the investigated on-site hydrogen production is not economically viable within the current (2019) framework of the German energy sector. Assuming the extensive availability of renewable power generation in the long-term, additional investigations indicate that on-site hydrogen production and storage systems for gas turbines could potentially become economically viable if various advantageous conditions are met. These conditions include a sufficient availability of inexpensive renewable power for the operation of electrolyzers as well as a sufficient utilization of on-site hydrogen storage capacities to justify corresponding capital expenditures.