Construction of Nord Stream 2 is now 83%complete but progress has been halted after the U.S. government threatened to impose sanctions on the Swiss pipe laying firm Allseas. Gazprom, the majority owner of the pipeline, vowed to complete the remaining 100-mile stretch with a Russian pipe laying vessel.

Once completed, the Uniper CEO could accept a quota that prescribes that a certain amount of Nord Stream’s throughput should be hydrogen. This measure would help transform wider northern European gas network towards mixing natural gas with hydrogen of any kind.

Green vs. blue hydrogen

The German government aims for global leadership in hydrogen technologies, considered crucial to make the economy carbon-neutral by 2050. However, the national hydrogen strategy has been delayed due to disagreements on targets for making ‘green hydrogen’, and on the extent to which ‘blue hydrogen’ made from natural gas using carbon capture storage (CCS) should be used as a transitional technology.

Advocating the use of ‘blue hydrogen’, Eurogas Secretary General, James Watson, noted that the fuel is likely to replace natural gas in some parts of EU pipeline system. “Instead of transporting only natural gas, Nord Stream 2 could transport 80% of the hydrogen,” he noted, pointing at the EU’s ambitious decarbonization program.

The industry association BDI opposes ruling out the use of ‘blue hydrogen’, arguing that insisting on green hydrogen would delay technology development given that sufficient volumes will not be available by 2030. The economy ministry's February draft of the German hydrogen strategy, seen by the Clean Energy Wire, said that while green hydrogen “is sustainable in the long term,” blue hydrogen “will have to play a role for economic reasons to quickly establish the technology in the market and to decarbonise various areas of application.”

Schierenbeck also said the strategy should include support for specific projects and some kind of national hydrogen market. "We will need both. For example, there is nothing to be said against prescribing that a certain amount of hydrogen is needed in the gas network, i.e. a quota."

In the first three months of 2020, Coal-fired power generation fell by over a quarter across the EU and the UK compared to the same period in 2019, while renewable energy reached a 43% share. The stark rise in intermittent wind and solar power in-feed to the grid, combined with lower load factors, makes grid balancing increasingly difficult.

The figures mark a dramatic shift in Europe’s energy mix – one that was not anticipated to occur until the end of the decade. The pandemic has effectively accelerated the energy transition in key European economies, providing a unique opportunity to see how energy systems function with far higher levels of renewables.

• In the UK, renewables now have a 43% share of overall generation (up 10% on the same 10 March to 10 April period in 2019) with coal power down 35% and gas down 24%.
• Germany has seen the renewables contribution reach 60% (up 12%) and coal generation fall 44%, resulting in a fall in the carbon intensity of its electricity of nearly one third.
• Spain currently has 49% renewables with coal power down by 41%, while Italy has seen the steepest fall in demand, down 21% so far.

The impact of pandemic on the European energy system is “extraordinary,” said Wärtsilä’s VP for Europe & Africa, Björn Ullbro. “We are seeing levels of renewable electricity that some people believed would cause systems to collapse, yet they haven’t – in fact they are coping well.”

These figures come from the Wärtsilä Energy Transition Lab, a new free-to-use data platform developed by Wärtsilä to help understand the impact of the corona crisis. The platform provides data on electricity generation, demand and pricing for all 27 EU countries and the UK, combining Entso-E data in a single platform. It allows users to model how systems could operate in future with higher renewables, helping pinpoint problem areas and highlight where to focus policy and investment.

German federal states and utilities are urging state energy ministers in a position paper to expand Germany's power grid and renewable energies as part of an economic stimulus package. The aim is to speed up investments in hybrid power sources, energy storage and hydrogen – much of which would have become necessary anyway over the course of the next decade anyway.

Delay national CO2 price on transport?

Several states want to put climate policy on the back burner, arguing that projects like the Green Deal would pose additional obstacles to economic recovery. Likewise, industry associations have said tighter environmental standards could hinder their ability to react to the coronavirus crisis, calling for some stringent rules to be relaxed.

The pro-business party FDP questioned the introduction of a national price on carbon emissions in heating and transport, and some conservatives call for suspending the aviation tax planned in Germany's Climate Action Programme for at least one year.

Merkel remains firm on climate targets

German Chancellor Angela Merkel, in contrast, remains committed to climate action. She stressed “this issue has not gone away during the pandemic.” Finance minister Olaf Scholz said a stimulus package oriented toward international climate targets and Germany’s goal of becoming carbon neutral by 2050 would "make sense," as soon as the most pressing phase of the pandemic has ended.

Proposals include clean energy tax credits, requirements that bailed-out industries like airlines commit to emissions cuts, and investments in green infrastructure. This approach could both ensure that climate action is not neglected during the crisis, and help Germany stay competitive in energy transition technologies, a sector that could be worth about 23 trillion dollars by 2030, according to the World Bank.

Lockdowns to contain the coronavirus caused a 6.5% drop in Italy’s overall gas consumption in January through March, dragged down by a 10% drop in gas-burn for power generation and an 8.8% fall in industrial gas consumption.

For 2020, Italian gas demand will not recover to pre-year levels, the GEFC’s head of gas market analysis Mahdjouba Belaifa commented. Demand is unlikely to exceed 70 Bcm, he forecast, as aftershock effects continue to threaten the economic recovery this year. Milder weather than expected also slows the pace of gas demand recovery, despite continuously falling gas and LNG prices in Europe.

Energy demand fell off a cliff

Industrial gas demand fell sharply in Italy following the March 12 lockdown to just 20 million cubic meters per day (mcm/d), compared to an average consumption of 71 mcm/ on March 10 and 11. In the power sector, gas consumption declined from 47 mcm/d before the lockdown to around 36 mcm/d by the end of March, a drop of 24%.

The sharp drop reverses a trend of rising gas consumption in the previous years when Italian utilities and industries took advantage of record low gas prices as oversupply keeps building up on global markets. In 2019, Italy’s overall gas consumption expanded by 1.7 Bcm, or 2.3%, to reach a total of 73.8 Bcm.

Gas-burn for power generation increased by 10%, more than offsetting the drop in gas consumption in the residential (-2%) and industrial sector (-1.8%), figures by the Italian network operator SNAM Rete Gas show.

US LNG imports now “uneconomic”

As Europe’s third largest gas markets, Italy’s imports are characterized by long-term gas supply contracts and some minor volumes of spot LNG. In recent years, imports originated mostly from Russia (42.1%), Algeria (17.9%), Libya (8.1%), Netherland and Norway (15.7%) and Qatar (11.2%).

Imports in 2019 increased 4.8% year-on-year as utility buyers and industry took advantage of the positive spread between prices at the Dutch trading hub TTF and the Italian PSV, resulting in higher gas flows via the northern interconnector at Passo Gries. Spot LNG shipments to Italy were also on the rise following a global production glut that turned Europe into a market of last resort.

In 2020, however, demand destruction due to the pandemic is expected to challenge imports of US LNG which used to account for 3.55 mpta, or 5% of Italy’s natural gas imports. The Doha-headquartered GEFC says at today’s record low gas prices “it becomes uneconomic for US producers to export LNG to Europe and to Italy in particular.”

A probable recession would harm imports, with any demand recovery largely depending on when the coronavirus will be contained. For the remainder of this year, GEFC senior gas market analyst Rafik Amara does not see Italian gas consumptionrecover to more than 2016-levels, as imports post the pandemic “will not peak significantly.”

Whiting Petroleum became the first U.S. upstream company to file for bankruptcy on April 1. Others are not far off, notable Chesapeake Energy and Denbury Resources which are understood to have hired debt advisors. Chesapeake is struggling with a debt burden of nearly $9 billion, up 900 million from the previous year due to the acquisition of Wildhorse Resource Development.

The risk of bankruptcies looms large among U.S. fracking companies which struggle with demand destruction as the coronavirus pandemic has brought major economies worldwide to a halt. Gradual relaxation of lockdowns and an agreement of OPEC+ to reduce oil production are hoped to lift prices starting from the second quarter.

Lenders aim to seize shale assets

Debt financiers of U.S. fracking companies are preparing to directly manage distressed energy assets to avoid debt write-offs in the event of bankruptcies. Bank of America, Citigroup, JP Morgan Chase and Wells Bank are busy working on setting up holding companies for distressed oil and gas producers as the industry owes over $200 billion to lenders.

Smaller U.S. oil and gas producers, also known as wildcatters, have been heavily reliant on banks for liquidity over the past twelve month, as debt and equity finance options dried up. Lender have been conservative in valuing hydrocarbon reserves used as collateral, but the recent slump in oil prices have left them worried.

Alta Mesa Resources and Sanchez Energy are two out of a bunch of energy companies at risk. Should the former go bust, banks are understood to get less than two-thirds of their loans, while a bankruptcy of Sanchez Energy could leave them empty-handed. Hence, some banks are hinting they will foreclose on an energy company and its properties if they do not repay their loan.

Banks could manage fracking firms for one year

By retaining such distressed companies temporarily in separate holdings, banks can avoid having to sell the assets for cheap. Instead, lenders could manage these indebted energy companies until oil prices recover enough so that the assets could be sold at a higher value.

However, banks would have to get a regulatory permission to realize their plans because of limitations on their involvement with physical commodities, sources told Reuters. By holding the assets for only one year, banks are hoping to comply with current Federal Reserve rules.

These day, the banks are understood to set up holding companies to bundle limited liability companies (LLCs) containing the distressed and seized assets. These LLCs would be held proportionally by the banks and financiers that handed out the original secured loan.

Rising share of renewables energy can lead to congestion and complexity within the grid. Smart grids, along with fast-ramp gas gensets and energy storage, alleviate these issues and facilitate easier grid balancing.

Monitoring load changes through smart grid also help reduce transmission and distribution losses across the electricity supply chain. Demand respond technology and smart metering are expected to be widely implemented across ASEAN, as the bloc of states embraces digitalization.

Consumer energy management, known as ‚smart home controller‘, can help households monitor and regulate their energy demand. Ultimately, this helps end-customers lower their gas and electricity bills and can be used by distributors as a steering instrument to flatten demand peaks.

The speed and scope of smart grid rollouts vary significantly across the different ASEAN countries. Singapore and Malaysia are frontrunners, owing to constant product innovation, expansion of automated technologies in small-scale holdings and favorable government support for renewable energy and related technologies.

Adverse effects on Enagás sales and earnings become more visible when April figures are considered as well. “So far this year, total demand through April 20 decreased by 5.8%compared with the same period last year,” the Spanish gas grid operator said.

Lower gas-burn for power gen

“This drop was the result of a fall in gas consumption by industry and business customers since the State of Emergency was established in Spain for the pandemic, while there was lower demand for electricity generation,” it explained.

Enagás’ earnings through March 31 reached €235.6 million, up 2.5% from €229.9 million in the previous quarter. The Madrid-based company achieved a profit after tax of €119.1 million, up 14.9%.

Keeping LNG flowing

The positive results, in the face of the corona crisis, were achieved by enacting special working measures to keep LNG flowing at Enagás’ three main regasification terminals. "We launched a Coronavirus Contingency Plan and the Spanish Gas System operated normally,” stated Enagás.

“In the three main regas plants in Spain, in Barcelona, Cartagena and Huelva, a special work system was established that included the confinement of two operator shifts for 15 days,” company explained. “In addition, the shifts were working in parallel with two control centres for greater security,”

The Spanish TSO has four domestic import terminals around Spain also operates the Gijon LNG regas plant in the northwest and owns a 50% stake in the facility serving the city of Bilbao.

Lockdowns in Japan and India to contain the coronavirus have softened the JKM (Japan Korea Marker) near curve relative to prices at the Dutch TTF gas trading hub. The JKM-TTF spreads for summer delivery were last seen in the range of 0.22–0.53 $/mmbtu, with the upper bound set by the freight differential for US cargoes delivering to Europe and Northeast Asia.

Japan sticks to coal

In Japan, analysts see fuel switching as less likely, given the low prices required. Forecasts for Brent oil prices for the remainder of 2020 are forecast are not low enough to support a Japanese power sector coal-to-gas fuel switch.

Japanese historic customs data suggest oil-indexed imports on a 14% slope against crude prices with a fixed premium of 0.8 $/mmBtu. According to Energy Aspects, crude prices would need to average below $23/bbl for oil-indexed LNG to be competitive against a coal-to-gas fuel-switch price of 4 $/mmbtu – accounting for delivered coal prices and differences in generation efficiencies for coal and gas.

Korea’s coal tax pushes balance to LNG

South Korea, in contrast, only needs oil-indexed prices to be below $42/bbl for it to make state-owned supplier KOGAS’s import prices low enough for a fuel switch. The higher fuel switch level is because thermal coal is taxed at a higher rate since April 2019 than natural gas when used for power generation.

Utilities’ would start dispatching more gas-fired power plants as soon as KOGAS translates these lower import costs into lower tariffs to these firms. Analysts note that KOGAS has little scope to absorb spot supply on top of existing commitments, with 29.6 Mtpa of supply under long-term contracts.

KOGAS’s reported requests for delayed cargo deliveries over the coming months suggest that its higher y/y LNG inventories have left it with little ability to receive all its contracted supply. But Energy Aspects pointed out that “any fuel switch would not likely be in play until at least July.”

The marine and energy markets in which Wärsilä operates are being affected by the lockdowns to contain the global pandemic. Uncertainty abounds about the financial impact of these measures hence the Finish manufacturer withdrew its market outlook for 2020.

The steep fall in order intake resulted in a lower orderbook for the January to March period, down 5% at € 5,745 million. Though net sales increased by 2% to €1,170 million, the operating result fell to €56 million, down from €102 million in Q1-2019, which represents 4.8% of net sales.

“During the first quarter of 2020, our business environment was characterised by a sudden increase in uncertainty related to the coronavirus pandemic and its longer-term impact on the global economy. Net sales increased slightly from the corresponding period last year, thanks to growth in both equipment deliveries and service activity in the Marine Business,” the Wärtsilä CEO said.

“Energy equipment deliveries, on the other hand, declined largely due to project timing and some COVID-19 related delays [given that] factories running at lower than usual capacity and in restricted mobility of field service personnel,” he added.

Wärtsilä’s operating result was consequently impacted by weaker fixed cost absorption, slower delivery of projects and service sales which are affected by cost overruns.

Demand still “reasonable”

Demand in the first quarter was “reasonable, considering the prevailing market conditions,” Mr. Eskola said. Equipment order intake in the Energy Business improved, thanks to the turnkey contracts received for two large power plants in Latin America.

The effects of the pandemic have severely affected Wärtsilä’s cruise segment, while several energy project sites have been demobilised. The risk of a global recession has prompted shipowners and operators to re-evaluate their investment plans. Similarly, in the energy markets, deteriorating macroeconomic conditions and the anticipated decrease in electricity consumption are resulting in postponed investment decisions for new power generation capacity.

Cutting labour costs

To mitigate the weakened demand outlook, combined with lower project delivery, Wärtsilä has taken proactive steps to lower our cost base with approximately EUR 100 million. These cost cuts were achieved by reducing working hours and initiating temporary layoffs, as well as by limiting the use of external personnel and consultants.

The first concrete actions have already been taken in locations where operations have been adversely impacted by the pandemic, Wärtsilä said without specifying.

Looking ahead, Wärtsilä will reduce discretionary spending but will keep investing in R&D projects on alternative fuels for the shipping and energy sector. Advances have been made testing the use of ammonia in our engines and fuel systems, backed by Finish government funding for the X-Ahead project, aimed at developing the technical and business potential of Power-to-X.

Once in full swing, the flexible CCGT will be used to back up intermittent supply from wind and solar power units. Operational flexibility was a key focus of New York regulators, who required the plant operators to upgrade the nearby power grid and substations to allow for swift electricity in-feed for balancing purposes.

Construction works for the Cricket Valley CCGT began in January 2017, led by Bechtel as the engineering, procurement and construction (EPC) contractor on the project.

Powered by GE’s 7FA gas turbines, the power plant will provide more cost-effective electricity with lower emissions than many existing plants in the downstate region of New York. The flexible CCGT will mostly provide electricity to a supply-constrained lower Hudson Valley and New York City markets.

Cricket Valley Energy Center LLC, part of Advanced Power, developed the project at an estimated cost of $1.58 billion. JERA Americas is the largest investor on the project next to Idemitsu Kosan, Nuveen, Black Rock, Development Bank of Japan (DBJ), NongHyup Financial Group (NHFG), and Kiwoom.

Advanced Power has ample experience in acquiring or building and operating power generation assets throughout Europe and North Americ., including the 700-MW Carroll County CCGT in Ohio. The Swiss-based company has developed a total of 15,000 MW of power generation capacity, and subsequently closed $7 billion of limited recourse project financing.

Situated in Taoyuan, some 50 kilometers west of Taipei, the Datan Power Plant consists of seven power units, all supplied by MHPS. Unit 1-6 already run in combined-cycle mode, generating a combined output of 4,200 MW.

Unit 7, the focus of this project, is comprised of two simple cycle gas turbines supplied by other company, and began operations in 2018. The operator of the entire plant is Taiwan Power Company (TPC)

The conversion will be jointly carried out by MHPS and Mitsubishi, with the former set to supply one steam turbine and one electric power generator, along with auxiliary equipment and spare parts. The steam turbine and electric power generator will be manufactured at MHPS’ Hitachi Works in Hitachi, Ibaraki Prefecture, Japan.

State-owned TPC manages 75% of the total electricity generation in Taiwan and is seeking to expand its capacity further. In this context, MHP has already built the 2,600 MW Tunghsiao Power Plant in Miaoli County and is now working on various gas combined-cycle conversions to enhance operational flexibility and increase output.

Stimulus-fuelled investment to rekindle economies after the corona crisis could help trigger a large-scale rollout of green energy sources and drive cost declines as the technologies progress. Both lithium-ion batteries and electrolysers are at the stage in their development where wind and solar were in 2008-2009, the IEA executive director Fatih Birol said, suggesting “they have the potential to be the coming decade’s breakout technologies.”

Similar support schemes were once set up for wind and solar PV – “today both are cost-competitive in large parts of the global energy system in their own right,” Dr. Birol noted. Offshore wind, in particular, “is now ready for massive investment,” he stressed. Wind turbines are based on mechanical engineering in which European countries, especially Germany, have a comparative advantage. But solar panels are an extension of semiconductor electronics, an area where China already had a competitive edge.

Clean energy stimulus rekindles economy

Trying to revive the economy, governments around the world are cobbling together massive stimulus packages. These huge public spending programs will shape countries’ infrastructure and energy systems for decades to come.

Time is of the essence, given that the pandemic has triggered the biggest economic collapse since the Great Depression. Hence, the IEA is urging national government to put clean energy jobs at the centre of stimulus packages. Investing in energy efficiency also has large benefits for employment; previous stimulus plans in the United States and elsewhere supported large numbers of jobs by fuelling demand for the labour-intensive work of upgrading building.

Electricity and internet networks are vital to keep professionals connected while working from home and help industries get through the current crisis. However, current grids are not ready for a more electrified future in which wind and solar account for a rising share of power generation, the IEA warned. Governments should hence help TSO to integrate smart digital technologies in their operation to enhance grid stability.

Electricity demand is down between 5 and 10% across major markets in Europe but Wood Mackenzie analysts see “early signs of an up-turn” in Spain where lockdowns were lifted early. Denmark, Germany, Switzerland and Austria are also taking steps to end the lockdown as coronavirus infection rates start to fall.

EDF curtails nuclear output

Forward power prices, depressed due to demand destruction, rose last week in reaction to EDF’s announcement that output from the French nuclear fleet will fall to 300 TWh in 2020, down from 380 TWh in 2019. EDF seems to „reserve the reactor fuel for winter 2020/21,” analyst suggested. The lower nuclear output will limit the volume of electricity France exports to its neighbours which is seen “offering potential relief to thermal generators.”

Gas-fired power plants, in particular, could benefit from the lower dispatch of nuclear for baseload power supply. Thermal generation is kept running in several European markets to provide flexibility for the current high levels of renewable energy supply.

Grid edge technologies have come to the test as operators of both power plants and networks increasingly turn to remote diagnostics and operations as the pandemic is preventing onsite work.

Storage roll-out faces delays

Energy storage can also provide flexibility, but large projects are delayed as lockdowns have interrupted key supply chains. Wood Mackenzie anticipates the coronavirus could lower 2020 installations by 20% compared to the consultancy’s 2020 base case.

The risk for distributed storage to be delayed, or even cancelled, is most acute, analysts noted. A return to pre-coronavirus impact levels is deemed unlikely before 2021.

In a fast recovery scenario, German baseload power could still cost 21% less than before the coronavirus stifled the Europe’s largest economy and pulled southern Europe on the brink of a recession.

Lockdowns of industries and much of the service sector throughout Europe have led to a steep drop in electricity demand, with energy-related carbon emission likely to drop by more than 100 million tonnes.

Earlier coal exit?

The fuel switch from coal to gas-fired power generation, which started before the crisis due to a high price on carbon and falling gas prices due to global oversupply, is bound to continue, DNV GL forecasts.

Earlier shutdowns of some coal power plants "could come into consideration in the event of a slow recovery of the global economy", analysts said, suggesting Germany might then have to import more electricity on a temporary basis.

Higher RES contribution

Renewable energy sources are covering a rising share of Germany’s power demand, which fell off a cliff due to the health crisis. More than half of all electricity produced in Germany came from renewable power sources, for the first time over an entire quarter during the first three months of 2020.

The intermittent nature of wind and solar power supply, combined with its growing contribution, has greatly increased the volatility of wholesale power prices, and occasionally causes negative prices.

Storing excess volumes of intermittent wind and solar energy in batteries, or in the form of hydrogen via electrolysis, would help balance the grid. Investment in commercializing these technologies will be helped by a state stimulus package, designed to revive the economy in the aftermath of the pandemic.

Turbine blades are currently made of single crystal nickel (Ni)- or cobalt (Co)-based superalloys. After many years of refinements, their development has plateaued. Researchers are hence trying to leverage and integrate recent advances in alloy design and modeling, refractory alloys, advanced manufacturing technologies, and high-throughput testing to realize significant improvements in the operational capability of gas turbines.

Turning up the heat

The temperature capability of current state-of-the-art blade materials has improved steadily over the last few decades to 1100 ºC, through incremental microstructure and chemistry refinement.

The ULTIMATE program targets enabling gas-turbines blades to operate continuously at 1300 ºC in a material test environment—or with coatings, with turbine inlet temperatures of 1800 ºC or higher. ULTIMATE stands for Ultrahigh Temperature Impervious Materials Advancing Turbine Efficiency, and is part of the ARPA-E program series.

The use of novel materials can boost temperature and potentially increase gas turbine efficiency up to 7%, improving power plant economics. By 2050, such a 7% efficiency improvement in gas turbines used for U.S. electricity generation could save up to 15-16 quads of energy, researchers said. For aircraft turbines the energy savings could be 3-4 quads.

Research will be conducted in two phase, covering proposed for a maximum of 18 and 24 months. In phase I, project teams will demonstrate proof of concept of their alloy compositions, coatings, and manufacturing processes through modeling and laboratory scale tensile coupon (sample) testing of basic properties. In phase II, approved project teams will investigate selected alloy compositions and coatings to evaluate a comprehensive suite of physical, chemical, and mechanical properties as well as produce generic small-scale turbine blades to demonstrate manufacturability.

Propping up manufactures

Natural gas turbines currently produce an estimated 35% of the electricity generated across the United States. The DOE research grant can help turbine developers to trial and commercialize new turbine coatings to enhance their sales in the current difficult economic environment.

According to ARPA-E Director Lane Genatowski, the novel ultrahigh-temperature alloys in conjunction with coatings are meant to boost efficiency of gas turbines, used both for power generation and aviation.

“Developing new, innovative technologies under the ULTIMATE program will allow us to better utilize gas turbines across multiple power sectors, from electricity generation to transportation and aviation,” said DOE Undersecretary of Energy Mark W. Menezes. In the long-run, the DOE-aided research is mean to help “making all of these industries more efficient,” he concluded.

To develop such Power-to-X-Power solutions, ETN and its cooperation partners have embarked on the FLEXnCONFU project, short for FLEXibilize combined cycle power plant through Power-to-X solutions using non-CONventional Fuels. The project has a total budget of 12.6 million Euros and runs from April 2020 to the end of March 2024.

Co-firing reduces Opex

Hydrogen and ammonia, produced at low cost from excess supply of wind and solar power, can be stored and used as a cheap fuel by retrofitted combined-cycle gas power stations. Co-firing capability reduces the plant’s operating cost which can help increase their current low operating-hours.

To level the combined-cycle load, excess thermal electricity can also be converted into hydrogen or ammonia for re-use in the same power plant, if and when needed to respond to varying demand.

The new FLEXnCONFU layout is improving the fuel flexibility of gas-fired  power plants and their overall efficiency. It can be retrofitted to combined heat and power units, flexible combined-cycle units or integrated coal gasification unit.

Trials at Ribatejo CCGT start in March 2023

To demonstrate the economically viable solutions, EDP will install a Power-to-Hydrogen system in a real operating environment at its Ribatejo combined-cyle gas power plant (3 x 392 MW), situated some 30 kilometers northeast of Lisbon. The three units, powered by Siemens V94.3A gas turbines in single shaft configuration, have a combined capacity of 1.176 MW.

Installation and commissioning of the developed technologies at Ribatejo plant will start in September 2021. Siemens, the subcontractor for the project, will handle the retrofit of the combustion chamber as other components. The actual trial runs to demonstrate the hydrogen co-firing are scheduled to start in March 2023.

Micro-turbine trials with ammonia

At the same time, a Power-to-Ammonia system will be installed at a micro gas turbine operating in a smart grid context at the Savona lab. In addition, tests with up to 100% ammonia co-firing at a heavy-duty gas turbine will be performed at Cardiff University’s combustion lab.

The consortium behind the FLEXnCONFU project is led by RINA Consulting. Partners include EDP, Backer Hughes, Cummins affiliate Hydrogenics, Proton Ventures, Tirreno Power, ENGI Laborelec, ICI Caldaie, MAS Advanced Technologies for Power and Energy as well as several European research institutions.

In the Northeast region, access to abundant natural gas supply from the Marcellus and Utica shale plays in Pennsylvania and Ohio has led to increases in natural gas-fired power plant capacity.

Similarly, access to high quality wind resources in the Midwest region has led to increases in wind capacity. In both cases, these additions have replaced coal-fired capacity. Nearly 14,000 MW of coal-fired capacity was retired in 2019—the third-most annual coal retirements in EIA’s power plant inventory.

Although total electricity generation across the United States has remained relatively flat since the mid-2000s, power plant installations have continued to increase in the past decade, partly to replace retiring coal-fired plants.

Low natural gas prices, a rapid decline in construction costs for solar and wind systems, and an increase in renewable portfolio standard requirements in many states have led to more generation from natural gas-fired and renewable resources in many regions. In 2010, coal was the predominant source of electricity generation in the United States as a whole and in every region except the Northeast.

In 2019, coal was the most-used electricity generation source in only the Midwest.

Inspection works included the repair of several key components of the power unit, notably components of the combustion chamber. The overhaul extends the overhaul interval of the SGT 800 turbine by 25%, which is equivalent to approximately seven months of operations.

The 519 MW power plant, one of the largest in Bashkortostan, provides heat to more than half of the residents and industrial facilities in city of Ufa, with more than 1 million inhabitants. The upgraded plant allows the operator Bashkir Generation’s better cope with Russia’s winter season, which typically lasts from October until May.

Use of localized resources

Onsite works were carried out by the GE Energy Technology Center in Kaluga, situated some 150 kilometers south of Moscow.

“Completion of such a comprehensive inspection project at the TPP-2 plant in Ufa was delivered through the collaboration of GE’s Cross-Fleet Solutions team, the repairs team in Birr, Switzerland, and the field services execution arm FieldCore,” said Michael Rechsteiner, Vice President for Europe at GE Gas Power. He underlined the use of localized resources made it possible to organize this task in the most time-efficient way.

Spare parts warehouse in Kaluga

GE’s Cross-Fleet Solutions offering provides an increase of maintenance intervals for Siemens’ SGT-800 units of up to 40,000 hours/900 starts, enhancements to plant output by up to 6% and efficiency by up to 1.5% (depending on the turbine rating). Most of the maintenance is carried out in the GE Energy Technology Center in Kaluga, where GE also has a localized SGT-800 spare parts warehouse to ensure the availability of its key components and provides the possibility of replacing them promptly – up to within 24 hours.

GE’s presence in Russia, especially in Kalgua, is crucial for regional customers. In 2018, GE managed to bring an SGT-800 unit at Ufa TPP-2 back online within 24 hours and subsequently won a multiyear service contract with Bashkir Generation Company.

Striving to mitigate the risk of blackouts, JERA has put in place emergency measures to keep LNG flowing to keep system-critical power stations operational.

“We have multiple measures to maintain a stable supply even if the infection spreads,” the Japanese financial daily Nikkei cited a JERA official. “If commuting becomes too risky, employees will sleep at the power station.”

Shipments with LNG cargoes still arriving “constantly”, he said but admitted if a few shipments were to be missed this could herald “an extended [electricity] cut-off.”

Nuclear gives no leeway

Japan has already faced a power shortage this year, and given that the number of nuclear power stations in operation is set to fall from nine to four or five, Japanese utilities have little leeway as they cannot rely on nuclear baseload power.

Tokyo Electric is understood to be rushing to restart its Kashiwazaki-Kariwa nuclear plant in Niigata Prefecture because the heavy concentration of LNG-fuelled power plants makes the region vulnerable in the event of gas supply shortages. Should gas stock run low, the region would be the first to experience power cuts.

Before the Fukushima disaster in March 2011, Japan had over 50 nuclear plants in operation but now has to make do with a tenth of that power. The Sendai reactor was shut down in March 2020 as it failed to meet anti-terrorism charges, Itaka nuclear unit 3 is offline due to a court injunction, and the Genkei reactor was shut after a contractor tested positive for the coronavirus.

Tokyo Bay heavily reliant on LNG

A stable supply of regasified LNG to operate gas-fired power units has become system-critical to keep the lights on, especially in Tokyo Bay which stretches around the prefectures of Chiba, Tokyo and Kanagawa. The highly industrialized region is Japan’s prime LNG hub and a centre of gas-fired power generation.

The LNG needs of these Tokyo area power plants account for 30% of Japan’s total gas-burn, producing 26 million kilowatts (kW) of electricity. Many of these gas power units are operated by JERA.

Demand-side response via energy storage will decrease the College’s Global Adjustment Charge, which is a fee billed to all hydro customers in the province under Ontario’s 2009 Green Energy Act. These charges are typically 60% of the total annual electricity bill.

Wärtsilä said the energy system is scheduled to be delivered, installed and commissioned in autumn 2020.

System controlled by GEMS

The system includes GridSolv solution with lithium ion batteries, inverters, and all balance of plant equipment. Controlled by Wärtsilä’s GEMS energy management, the batteries are charged when the electrical load is less than a pre-determined limit, and discharged during peak loads. The system responds to price fluctuation, minimizes power consumption from the grid and also adapts to higher winter energy demand.

 “Ontario is committed to achieving a sustainable power supply and conforming with this objective by seeking a zero-emissions solution was important to us,” said Angela Lockridge, Georgian College Vice President. “The Wärtsilä energy storage solution will help to reduce the College’s electricity costs while supporting Ontario’s climate change mitigation strategies.”

The system will be used in Ontario for effective power management. “Managed by our advanced GEMS software, it is an efficient means for controlling demand charge type costs (and) responds to peak discharge events to cover the load,” said Wärtsilä’s Risto Paldanius, Director Energy Storage and Optimisation.