Câmara aprova PL Combustível do Futuro

  • Spanish Market: Biofuels, E-fuels, Natural gas, Oil products
  • 14/03/24

A Câmara dos Deputados aprovou o Projeto de Lei (PL) Combustível do Futuro na noite de ontem, abrindo caminho para o texto seguir para o Senado.

O governo do presidente Luiz Inácio Lula da Silva apresentou o pacote de transição energética em setembro, como parte de esforços de descarbonização para expandir o uso de renováveis e reduzir as emissões no país.

A indústria de biocombustíveis celebrou o progresso do projeto no Congresso. "A decisão vai inaugurar uma série de investimentos em novos biocombustíveis, ao mesmo tempo que garante os avanços já consolidados com o etanol e o biodiesel", afirmou a Associação dos Produtores de Biocombustíveis do Brasil (Aprobio).

"Este projeto vai estimular a agroindustrialização do interior do Brasil, já que o agronegócio está na base da produção dos biocombustíveis", disse a Frente Parlamentar Mista do Biodiesel (FPBio).

O PL posicionará os biocombustíveis no topo dos caminhos possíveis para a descarbonização, de acordo a União Nacional do Etanol de Milho (Unem).

"Também representa um passo significativo para o avanço de projetos de captura e armazenamento de carbono [CCS, na sigla em inglês], contribuindo para o avanço seguro e eficaz dessas iniciativas", disse Isabela Morbach, presidente do CCS Brasil, um centro de pesquisas especializado no setor.

As diretrizes estabelecidas incluem "ações que darão tração a inovações fundamentais com bioenergia na mobilidade, no setor de gás, na indústria aérea e nos processos de produção de biocombustíveis", ecoou a União da Indústria de Cana-de-Açúcar e Bioenergia (Unica).

A aprovação também é vista como um passo importante para o setor da aviação cumprir metas de redução de emissão de CO2, segundo a Associação Brasileira das Empresas Aéreas (Abear).

Ainda não há data para a votação do Combustível do Futuro no Senado.

Principais pontos do relatório aprovado

Mescla do etanol na gasolina: fixa em 27pc o percentual obrigatório de adição de anidro à gasolina, ao mesmo tempo em que estabelece que o poder executivo poderá elevá-lo até o limite de 35pc ou reduzi-lo a 22pc, dos atuais 18pc-27,5pc. Uma redução pode ser feita em caso de preços altos ou escassez de oferta.

Biodiesel: aumenta, gradualmente, o mandato obrigatório de mistura do biodiesel para 20pc até 2030, ante os atuais 14pc. O novo piso será de 13pc, alta em relação aos 6pc de hoje. Também estabelece que crescimentos acima de 15pc dependerão de "viabilidade técnica comprovada" e autoriza o Conselho Nacional de Política Energética (CNPE) a elevar o mix para 25pc a partir de 2031.

Biometano: o projeto propõe um programa nacional para incorporar o biometano na matriz de combustíveis do Brasil, com um mandato começando em 1pc em janeiro de 2026. O CNPE pode ajudar essa porcentagem até 10pc. Entretanto, a meta pode ser alterada em situações excepcionais como baixa oferta de mercado e alto custo.

SAF: define metas de emissões para as companhias aéreas, incentivando o aumento do uso de combustível de aviação sustentável (SAF, na sigla em inglês), visando alcançar uma redução de 1pc nas emissões para as companhias aéreas até 2027 e 10pc até 2037.

Captura e armazenamento de carbono (CCS, na sigla em inglês): propõe um marco regulatório para o exercício das atividades de captura e estocagem geológica de dióxido de carbono, cuja regulação será atribuída à Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP).

Diesel verde ou renovável: cria um programa nacional para incorporar o diesel verde ou renovável na matriz de combustíveis do país. O mandato de mistura será definido pelo CNPE e terá um piso de 3pc até 2027. O diesel com conteúdo renovável (diesel R) da Petrobras ficou de fora do texto.

E-fuels: estabelece meios legais que incentivem a produção dos chamados e-fuels, alternativas sintéticas aos combustíveis fósseis feitos a partir de hidrogênio e CO2.


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21/06/24

PetroVietnam, South Korea’s Mubo partner on gas

PetroVietnam, South Korea’s Mubo partner on gas

Singapore, 21 June (Argus) — Vietnam's state-owned PetroVietnam (PVN) today agreed an initial financing deal with the Korea Trade Insurance Corporation, also known as Mubo, to strengthen and streamline South Korean companies' participation in natural gas projects with PVN and its subsidiaries. The $1bn package has both mid- to long-term financial tranches available if South Korean companies secure PVN's natural gas projects. PVN has plans to expand its gas field development, pipeline construction and gas-fired power plants in projects valued at around $12bn. This is aligned with the government's plan to achieve carbon neutrality by 2050 through increased reliance on gas-fired power generation. PVN manages at least four gas-fired power plants, two coal-fired power plants and two hydropower plants, with 5404MW of total capacity, according to the firm. State-owned PetroVietnam Gas (PV Gas) is at the forefront of the gas power sector projects. It operates the 1mn t/yr Thi Vai LNG terminal, commissioned in July 2023 and has started supplying gas-fired power generation to industrial customers since 15 March. Vietnam is expecting to import more LNG, in anticipation of the start-up of the 1.6GW Nhon Trach LNG thermal power plant in November this year. The plant is comprised of two units that could require as much as 775,000 t/yr of LNG each, assuming a generating efficiency of 60pc. It is also building the 3.6mn t/yr Son My LNG import terminal in Binh Thuan province in southcentral Vietnam. The first phase of commercial operations is scheduled for 2027. A second and third phase at Son My will lift's Vietnam's overall LNG import capacity to 10mn t/yr. PV Gas is to supply 70,000t of LNG to state-owned utility EVN for use at its 715MW Phu My 3 thermal power plant in April and May, marking the first LNG supplies to the county's power sector. Russia has also expressed interest to partner with Vietnam for oil and gas supplies, including LNG, following a state visit by Russian President Vladimir Putin to Hanoi on 20 June. By Naomi Ong Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Indian regulator seeks oversight of LNG terminals


21/06/24
21/06/24

Indian regulator seeks oversight of LNG terminals

Mumbai, 21 June (Argus) — India's Petroleum and Natural Gas Regulatory Board (PNGRB) has issued a draft proposal for enhanced regulatory control over the country's existing and planned LNG import terminals. The draft regulations released earlier this month has PNGRB taking significant control of India's existing terminals, which includes approval of a new terminal or expansion of capacity following feasibility reports, as well as setting up pipeline infrastructure for regasified LNG. Each project would require a certification of registration by PNGRB and may even face penalties if there are any start-up delays. Developers will also need to publicly disclose their regasification tariffs and other charges for transparency. The regulations are seen as an effort to reverse dwindling utilisation rates at India's existing LNG import facilities, according to traders. The proposed regulatory framework may hinder new investments across India's gas sector more broadly by introducing the additional layer of oversight. PNGRB board of directors typically being short of members results in delays in approvals for existing projects or new products. The Indian Gas Exchange (IGX) small-scale LNG contract was delayed to launch in April this year from the initial plan of late 2023. The contract was needed to help supply gas consumers located in areas not served by pipelines. Plans to introduce LNG contracts for over one-month delivery on the IGX are also being held up because the board does not have sufficient staff to accelerate the speed of decision making, sources with knowledge of the matter said. Utilisation rates at India's seven LNG import terminals ranged from 15pc to 95pc in the April 2023-March 2024 fiscal year, with six operating at 30pc or lower despite a 16pc increase in LNG imports over the same period, oil ministry data show. Indian state-controlled LNG importer Petronet's 17.5mn t/yr Dahej LNG terminal had a 95pc utilisation rate, while Petronet's5mn t/yrKochi, state-controlled firm Gujarat State Petroleum's 5mn t/yr Mundra and state-controlled refiner IOC's 5mn t/yr Ennore terminals operated at 20pc or lower. India plans to add at least 25mn t of LNG import capacity in the next few years on top of its existing 47.7mn t/yr import capacity. India imports around 45pc of its daily gas needs, equivalent to around 190mn m³/d as LNG. The country plans to increase the share of gas in its energy mix to 15pc by 2030, which would increase overall demand to 600mn m³/d. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Brazil's Raizen ships 2G ethanol cargo to EU


20/06/24
20/06/24

Brazil's Raizen ships 2G ethanol cargo to EU

Sao Paulo, 20 June (Argus) — A second generation (2G) ethanol-producing unit of Brazil's top sugar and ethanol milling group Raizen — known as Bonfim Bioenergy Park — shipped its first cargo of 2G ethanol to the EU, vice-president Paulo Corte-Real Neves said. "We were already exporting E2G produced at the Costa Pinto unit," Neves said during the Argus Biofuels and Feedstocks Latin America conference, in Sao Paulo, Brazil. "Now, with the Bonfim plant, we have increased our relevance with customers and expanded the penetration of cellulosic ethanol." Bonfim Bioenergy Park is Raizen's second unit to sell 2G ethanol. The first is Costa Pinto Bioenergy Park. Both are in Sao Paulo state and produce a combined 112mn liters/yr (1,940 b/d), chief executive Ricardo Mussa said in May. Raizen said last year it sold 80pc of Bonfim's output to international markets. It now expects to sell the remainder on the EU ethanol spot market. Raizen, a joint venture between Shell and Brazilian conglomerate Cosan, has plans to have 20 2G ethanol units in operation in 10 years, with total installed capacity reaching up to 1.6bn l/yr (27,750 b/d) when works are finished. By Maeli Prado Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Global gas flaring up by 7pc in 2023


20/06/24
20/06/24

Global gas flaring up by 7pc in 2023

London, 20 June (Argus) — Gas flaring from hydrocarbon production rose by 7pc in 2023 to 148bn m³, the highest level since 2019, according to a report by the Global Flaring and Methane Reduction Partnership (GFMRP). The GFMRP, an initiative managed by the World Bank, has since 2011 used satellites to gather data and create an inventory of global flaring. And volumes flared last year rose to the highest since 2019, reversing a fall in 2022. The gas flared could have had a market value of $9bn-48bn, assuming either US Henry Hub prices on the low end or European import prices on the high end, according to the GFMRP. And assuming all these flares operated with a 98pc destruction efficiency, the volumes flared would have resulted in 381mn t of CO2 equivalent (CO2e) of emissions, although if some flares were lower efficiency, they would have emitted more methane and CO2e emissions could be higher, the GFMRP said. The countries where the biggest increase in flaring was reported were Iran, Russia and the US. Volumes flared increased by 3.2bn m³, 2.9bn m³ and 1.7bn m³ in these countries, respectively, compared with 2022. Iran's emissions were higher because of an increase in oil production without a parallel investment in the infrastructure required to use the associated gas produced. The increase in Russia was uniform across hydrocarbon provinces in the country, and might have been driven by supply chain problems limiting maintenance in the wake of the war in Ukraine, the report said. And the US rise in emissions was sharpest in the Permian basin, where power cuts in the record-breaking hot summer of last year might have left electrically-powered compressors in collecting infrastructure unable to run, leading to operators flaring produced gas instead. But emissions fell in some countries. The biggest fall was in Algeria, where 400mn m³ less gas was flared compared with 2022. Although oil production in the country also fell by 2pc, flaring intensity of production was still down by 3pc, which the report attributes to flare gas recovery projects implemented by state-controlled Sonatrach at Hassi Messaoud, the country's largest oil field. The company committed to more projects at other fields in 2023, which could deliver further reductions, the report said. And in Venezuela, oil production climbed by 7pc but methane emissions fell by 300mn m³ (4pc), leading to a 10pc reduction in overall intensity. Reductions in flaring were localised in oil fields in the north of Monagas state, linked to flare gas recovery infrastructure built in the region by state-controlled oil firm PdV. Nine countries collectively — the five named above, and Iraq, Libya, Nigeria and Mexico — are responsible for 75pc of global gas flaring, but only 46pc of oil production. Production facilities might flare gas for safety purposes or maintenance. At other oil-weighted sites, associated gas might be flared because there is no infrastructure to put it to use. By Rhys Talbot Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Japan’s MGC produces bio-methanol from sewage gas


20/06/24
20/06/24

Japan’s MGC produces bio-methanol from sewage gas

Tokyo, 20 June (Argus) — Japanese petrochemical producer Mitsubishi Gas Chemical (MGC) has begun commercial output of bio-methanol by using sewage gas at its Niigata plant in northwest Japan's Niigata prefecture, in its latest project to decarbonise methanol manufacturing. It buys sewage gas, consisting of methane and carbon dioxide (CO2), from Niigata prefecture's Niigougawa sewerage plant. But the volume of bio-methanol produced is inconsistent and limited, it said. Output of bio-methanol could be a minimum 1 t/d but is unlikely to exceed 10 t/d, depending on the feedstock volumes MGC can purchase, it added. The sewerage plant uses the gas for power generation. MGC is still looking for buyers of its bio-methanol, although it said it has found some potential users. It expects domestic sales as output is too low for exports. The company expects its bio-methanol to be used as petrochemical feedstock, marine fuel and power generation fuel. The company has also explored the feasibility of methanol production from CO2 and green hydrogen in partnership with Cement Australia. Japan's methanol consumption has been around 1.7mn-1.8mn t/yr, according to MGC, with demand expected to grow further. By Nanami Oki Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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