Brazil biogas seeks opportunities in bottlenecks
Brazilian biogas market participants are seeing opportunities where natural gas or other fuels struggle.
Biogas producer Gas Verde generates 130,000 m³/d of biomethane from its solid waste Seropedica project in Rio de Janeiro state. That biomethane is then sold to consumers who want to reduce emissions and distributed as compressed gas through distributor's Ultragaz biomethane-fired trucks, Gas Verde's commercial manager Marcelo Sodre said at the Brazilian biogas producers' association Abiogas technical seminar last week. That allows the company to reach natural gas consumers that are not connected to the pipeline network.
Brazilian piped gas distributor Naturgy has launched large-scale compressed natural gas and biomethane projects to also reach consumers distant from transportation pipelines. The company has been compressing biomethane and natural gas to distribute it via trucks into their concession area in Rio de Janeiro, according to gas distribution director Christiane Delart.
That allowed Naturgy to launch a "green cities" initiative, in which it prioritizes the supply of biomethane to cities that are not connected to pipelines. Conventional natural gas is used to ensure supply when biomethane production is not enough. There are eight cities in the program, with a combined 1.4mn m³/month demand for gas, and the firm is considering including other 29 cities.
Naturgy sees potential for smaller industries that are interested in completely substituting their natural gas demand for biomethane, while more prominent companies opt for partial substitutions. The company also sees the liberalized natural gas market as the main booster for this biomethane potential, Delart said.
Supergasbras, the Brazilian retail arm of dutch LPG distributor SHV Energy, points to biogas as a possible solution to its decarbonization challenges. The company is studying, in partnership with universities, generating bioLPG — a fuel that could replace fuel LPG and be distributed in vessels — from biogas, according to Priscila Maziero, Supergasbras' sustainability and biofuels manager.
BioLPG is produced using hydrotreated vegetable oil (HVO) as feedstock, which Brazil does not currently produce. Supergasbras' strategy is to implement new uses to existing technologies. Once the technology is fully developed and optimized, the company plans to scale up its results, distribute and test the fuel with selected clients.
Green hydrogen in focus
Using biogas as a step in the green hydrogen chain has also been on Brazilian market participants' radar.
German international co-operation agency GIZ has launched a public-private cooperation program to boost companies studying green hydrogen in developing countries.
One such company is German biogas producer Mele, which has been developing such a project in Brazil, according to Joao Favaro, GIZ's technical advisor. The company has partnered up with agrocooperatives in Parana state to study the use of swine waste and green hydrogen.
Other speakers at Abiogas' technical seminar also named upgrading biogas into biomethane as a possible step in a green hydrogen production chain. The upgrading process results in concentrated CO2 that could easily be used as feedstock for hydrogen generation.
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LNG imports loom as Australia unveils gas strategy
LNG imports loom as Australia unveils gas strategy
Sydney, 9 May (Argus) — Australia's federal government will attempt to reverse the decline in new gas developments by expediting projects, although a report has found it is unlikely to reverse an anticipated shortfall in southern states' supplies later this decade. Canberra's long-awaited Future Gas Strategy will form its future policy on the resource, following two years of uncertainty for the industrial sector. This follows the Labor party-led government's election in May 2022 and its dumping of the previous Liberal-National coalition administration's gas-fed recovery from Covid-19 policy, which emphasised bringing new supplies on line to drive down rising prices. Six principles have been outlined by the government — driving down emissions reductions to reach net zero emissions by 2050, making gas affordable for users during the transition, bringing new supplies on line, supporting a shift to "higher-value and non-substitutable gas uses", ensuring gas and power markets remain fit for purpose during the energy transition and maintaining Australia's status as a reliable trading partner for energy, including LNG. The report found that gas-fired power generation will likely provide grid firming as renewables replace older coal-fired plants. Peak daily gas demand could rise by a factor of two to three by 2043, according to projections, with gas-powered peaking generation labelled a "core component of the National Electricity Market to 2050 and beyond". But by the 2040s more alternatives to gas for peaking and firming are expected to become available. Supplies are forecast to dip significantly in the latter years of the decade, especially in gas-dependent southeast Australia, driven by the 86pc depletion of the region's producing fields. This reduced supplies will outpace a fall in demand , while rising demand is forecast because of the retirement of Western Australia's coal-fired power plants . The report found the causes of Australia's low exploration investment are "multifaceted", blaming the Covid-19 pandemic, difficulties with approvals processes , legal challenges, market interventions and a perceived decline in social licence. It added that international companies may focus on lower cost and lower risk fields in other countries. New sources Stricter enforcement of petroleum retention leases and domestic gas reservation policies are also likely to increase supplies, the report found, with term swap arrangements beneficial in increasing their certainty. Upwards pressure in transport costs is likely to result from increased piping of Queensland coal-bed methane gas to southern markets such as Victoria state, which could influence industrial users to relocate closer to gas fields in the future. Options canvassed to meet demand include more pipelines and processing plants and LNG import terminals , which would provide the fastest option but must overcome regulatory and commercial pressures, given the pricing of LNG would be higher than current domestic prices. Longer term supplies depend on the commerciality from unsanctioned projects such as Narrabri and in the Beetaloo and Surat basins, the report said. More supplies are needed to support exports under foundational LNG contracts, with an impact on the domestic market if Surat basin developments such as Atlas does not continue, the report said. Forecasts show LNG exporters have sufficient production from existing and committed facilities to meet forecast exports until 2027 if expected investments proceed. But beyond this new investment is required, especially for the 8.5mn t/yr Shell-operated Queensland-Curtis LNG at Gladstone. The Australian Energy Producers lobby, which represents upstream oil and gas businesses, said the strategy should now provide clear direction on national energy policy. But the Greens party, the main federal parliamentary group aside from Labor and the Liberal-National coalition, said any plans to continue gas extraction beyond 2050 will negate state and federal net zero 2050 climate targets. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Baltic April gas consumption rises on year
Baltic April gas consumption rises on year
London, 8 May (Argus) — Gas demand in the three Baltic states and Finland was up by 26pc on the year in April, although there were diverging trends in the different markets. Consumption in Finland, Estonia, Latvia and Lithuania totalled 3.56TWh, up from 2.82TWh a year earlier but down from 4.31TWh in March ( see data and download, graph ). That said, total demand was still well below the 2018-21 average for the month of 5.03TWh. Consumption was up on the year in all three Baltic countries, but Finnish demand edged down. This was the first month in which Finnish demand was lower on the year since April 2023. In contrast, Lithuanian consumption surged by nearly 50pc on the year, and was also higher than in February and March despite the end of the traditional heating season. Gas-fired power generation held broadly stable from a year earlier, totalling 305MW across the four countries compared with 301MW in April last year ( see gas-fired output table ). Output edged down in Estonia and Lithuania and dropped by 25MW in Finland, but this was offset by a 31MW increase on the year in Latvia. But, unlike in March, gas-fired output fell by 246MW, a large contributing factor to the lower gas demand on the month. Many combined heat and power plants will have switched off at around the end of March or mid-April as the traditional heating season came to a close, possibly driving the fall in gas-fired output. But renewables generation was also stronger in April than March, particularly in Finland, where wind output rose to 2.03GW from 1.63GW, while hydro also stepped up. In Lithuania, solar and waste-based production increased on the month. Demand was also stronger despite higher year-on-year minimum temperatures in all four capital cities, which may have curbed most residual heating demand after the end of the traditional heating season, although there was a brief cold snap towards the middle of the month that temporarily drove up demand ( see temperatures table ). With gas-fired power generation only marginally higher than a year earlier, and the warmer weather curbing residential demand, a possible uptick in industrial demand may have driven the aggregate rise in consumption. Average prices on the regional GET Baltic exchange were €33.30/MWh in April, up by 8pc on the month but 30pc lower than a year earlier, the exchange said. Prices increased in around the middle of April "due to the unexpectedly cold weather and the increased demand for gas in the market", but then fell again "as the weather warmed", GET Baltic chief executive Giedre Kurme said. There were a total of 2,400 transactions last month for a combined 642GWh of gas. Volumes sold on the Finnish market accounted for 42pc, the joint Latvian-Estonian market 33pc, and the remaining 25pc was sold in Lithuania. Klaipeda and Balticconnector to change flows The return of the Finnish-Estonian Balticconnector pipeline and the start of maintenance at the Klaipeda LNG terminal in Lithuania will drive changed flow patterns this month. The Balticconector resumed commercial operations on 22 April after being off line since 8 October following a rupture caused by a dragging ship anchor . The reconnection of Finland to its southern neighbours has allowed for strong southward flows since 22 April, at an average of 62 GWh/d on 22 April-7 May. Some of this gas is probably being injected into storage, with the region's only facility at Incukalns switching to net injections on 23 April from net withdrawals of 7 GWh/d earlier in the month. Net injections have since averaged 46 GWh/d on 23 April-6 May, the latest data from EU transparency body GIE show. Stocks at Incukalns ended the withdrawal season on 30 April at 11.29TWh, the highest since at least 2014 and well above the previous high from last year of 9.03TWh. Large volumes of gas that had been stored over the previous summer for export to Finland over the winter were left stranded in Incukalns after the Balticconnector went off line. And the Klaipeda LNG terminal began maintenance on 1 May, which will last until 15 June, as the terminal's Independence floating storage and regasification unit (FSRU) departed for dry-docking in Denmark. As a result, there were net exports from Poland to Lithuania for the first time since early November, at an average of 17 GWh/d on 1-7 May. Some of this gas could have been withdrawn from Ukrainian storage, with flows from Ukraine to Poland averaging 10 GWh/d over the same period. Lithuania's largest supplier Ignitis has said it stored some volumes in Ukraine. And flows at the Kiemenai border point with Latvia have also flipped towards Lithuania, averaging 11 GWh/d on 1-7 May, compared with net flows towards Latvia of 15 GWh/d in April. That said, there were no flows at the point on 6-26 April. By Brendan A'Hearn Finnish, Baltic average gas-fired power generation MW Apr-24 Apr-23 Mar-24 ± Apr 23 ± Mar 24 Estonia 5 6 7 -1 -2 Latvia 49 18 215 31 -166 Lithuania 46 47 52 -1 -6 Finland 205 230 277 -25 -72 Total 305 301 551 4 -246 — Entso-E Daily average minimum temperature in FinBalt capitals °C Apr-24 Apr-23 Mar-24 ± yr/yr ± m/m 2014-23 Apr avg Vilnius 5.22 3.83 0.93 1.39 4.29 2.63 Riga 5.01 4.98 1.93 0.03 3.08 3.65 Tallinn 2.00 1.46 -0.59 0.54 2.59 1.17 Helsinki 0.11 -0.45 -2.55 0.56 2.66 0.12 — Speedwell Finnish and Baltic April consumption by country GWh Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
New Zealand’s Genesis Energy to resume coal imports
New Zealand’s Genesis Energy to resume coal imports
Sydney, 8 May (Argus) — New Zealand's upstream firm and utility Genesis Energy plans to resume thermal coal imports later this year to feed its dual gas- and coal-fired Huntly power plant. The resumption was because of lower domestic gas production and rapidly declining coal stockpiles, and will mark the firm's first coal imports since 2022. Coal inventories at the 953MW Huntly plant, — New Zealand's largest power station by capacity and the country's only coal-fired facility — recently slipped below 500,000t, down from 624,000t at the end of March, and will fall below 350,000t by the end of the winter. This will trigger a need to purchase more coal to maintain a target operational stockpile of around 350,000t ahead of winters in 2025 and 2026, the company said on 8 May. Imports are currently the most efficient option for the quantity the company will need, with a delivery time of around three months, chief executive Malcolm Johns said. Genesis typically imports from Indonesia, the company told Argus . Gas production in New Zealand has dropped at a faster rate than expected, with major field production in April down by 33pc on the year, Genesis said. Lower gas availability typically leads to more coal burn, because the Huntly plant runs on gas and coal. This is in addition to an extended period of low hydropower inflows in recent months, which required higher thermal generation to ensure supply security. A prolonged outage at Huntly's unit 5 gas turbine between June 2023 and January 2024 also led to an even greater need for coal-fired generation, Genesis said. Biomass transition The company — which is 51pc owned by the state — is the second-largest power retailer in New Zealand, behind domestic utility Mercury, according to data from the Electricity Authority. It has a NZ$1.1bn ($659mn) programme for renewable power generation and grid-scale battery storage , which includes a potential replacement of coal with biomass at Huntly. But the transition to biomass "will take some years," Johns said. Genesis has successfully completed a biomass burn trial at Huntly last year and has collaboration agreements with potential New Zealand pellet suppliers, but there is currently no local source for the type of pellets needed for the plant. Genesis is hoping to move to formal agreements "as soon as counterparties are able". The company will not consider importing pellets, it told Argus . "We will only use biomass if we can secure a local New Zealand supply chain that is sustainable and cost-effective," it said. Domestic gas production New Zealand's three-party coalition government said separately on 8 May that the "material decline" in local gas production threatens energy security, blaming the previous Labour party-led government for "policy decisions which have disincentivised investment in gas production." The decisions — which were part of the former government's pledge to achieve a carbon-neutral economy by 2050 — led to a reduction in exploration for new gas resources since 2021, while suppressed maintenance drilling reduced production from existing gas fields, according to a joint release from energy minister Simeon Brown and resources minister Shane Jones. "Due to this significant reduction in gas production, the government has also been advised that some large gas consumers are expressing concern about their ability to secure gas contracts," the government said. Major industrial users such as Canada-based methanol producer Methanex have been forced to reduce production as a result, it noted. "We are working with the sector to increase production, and I will be introducing changes to the Crown Minerals Act to parliament this year that will revitalise the sector and increase production," Jones added. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
EPA sets new oil and gas methane reporting rules
EPA sets new oil and gas methane reporting rules
Washington, 7 May (Argus) — Federal regulators have updated emissions reporting requirements for oil and gas facilities as they prepare to implement a methane "waste" fee for the industry. The US Environmental Protection Agency (EPA) on Monday finalized new rules it says will improve the accuracy of data from the oil and gas sector under the federal greenhouse gas emissions reporting program. Oil and gas facility owners and operators will be required to estimate emissions from additional types of equipment under the rule, and they can draw on newer technologies, like remote sensing, to help estimate emissions. "EPA is applying the latest tools, cutting edge technology, and expertise to track and measure methane emissions from the oil and gas industry," agency administrator Michael Regan said. "Together, a combination of strong standards, good monitoring and reporting, and historic investments to cut methane pollution will ensure the US leads in the global transition to a clean energy economy." Data to support new fee The revisions to the "Subpart W" reporting requirements will be used to determine the amount of methane that will be subject to a "waste emissions charge" created by the Inflation Reduction Act. Under the law, the charge will be calculated based on the annual data that about 8,000 oil and gas sources are now required to report. The charge will begin at $900/t for 2024 methane emissions above a minimum threshold using current measurement data. It will then rise to $1,200/t in 2025 and $1,500/t in subsequent years. Industry officials had raised "serious concerns" about several aspects of the original proposal , warning it could lead to inflated emissions data. "We are reviewing the final rule and will work with Congress and the administration as we continue to reduce GHG emissions while producing the energy the world needs," American Petroleum Institute vice president of corporate policy Aaron Padilla said. The industry group previously said it will ask Congress to repeal the fee, which is only likely to occur if Republicans win control of the White House. Data collected since 2010 Oil and gas facilities have reported emissions under Subpart W since 2010. To simplify reporting, operators often count the equipment they have deployed, and use industry-wide averages to estimate emissions, in addition to other direct and indirect measurements. The industry has argued the Subpart W data is not accurate enough to collect the methane charge, which is expected to cost operators more than $6bn over the next decade. Environmental groups have had their own criticisms of the data, which they say omits vast amounts of emissions such as those from "super-emitter" events and poorly maintained flares. The final rule seeks to respond to some of those concerns by relying on updated emission factors, incorporating additional empirical data on emission rates, collecting data at a more granular level and relying on remote sensing technologies to detect large emission events. EPA also revised Subpart W to include more types of sources, including produced water tanks, nitrogen removal units and crankcase venting. The final rule also sets a threshold of 100 kg/hr of methane for requiring the reporting of emissions from "other large release events." The new data rules will take effect on 1 January 2025 and will first apply to reports submitted in early 2026 for next year's emissions. EPA is allowing the use of the new methodologies for calculating 2024 emissions, but operators can still use the existing rules. By Michael Ball Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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