NGS’ NG/LNG SNAPSHOT – Jan-1-15, 2024
National News Internatonal News
NATIONAL NEWS
City Gas Distribution & Auto LPG
CNG vehicles introduced in Vizag Port
The Visakhapatnam Port Authority (VPA) Chairman Dr. M. Angamuthu Flaged-Off two CNG (Compressed Natural Gas) Buses and two Heavy Duty Truck Mounted Road Sweeping Machine here on Friday. The chairperson stated that CNG Buses are introduced for the first time in the port automotive segment. Promoting CNG Vehicles was a part of a series of Green Port initiatives being taken up by VPA and the same was a part of the Atmanirbhar Bharat campaign.
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With reference to Industrial Sweeping Machines, he stated that VPA is committed to maintaining Swachhata all over the Port premises and to ensuring high standards of cleanliness at Docks. A total expenditure of Rs.9.68 crores was going to be incurred by VPA for a period of three years in connection with the above two projects. The projects shall play a vital role in improving Environmental Quality and achieving Clean Port Standards. The Initiatives will further help VPA to transform itself into a Global Port.
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Minister of Petroleum and Natural Gas Shri Hardeep Singh Puri dedicated 17 AG&P Pratham’s CNG stations in Hassan, Chikkamagaluru, and Kodagu
Hassan: Minister of Petroleum and Natural Gas Shri Hardeep Singh Puri dedicated 17 AG&P Pratham’s CNG stations in Hassan, Chikkamagaluru, and Kodagu Geographical Area to the people today, in the presence of Shri Abhilesh Gupta – Managing Director and CEO, AG&P Pratham and Shri Takeshi Shinohara – Senior General Manager, Osaka Gas, Japan, along with other dignitaries from AG&P Pratham, Osaka Gas and HPCL. In the state of Karnataka, AG&P Pratham operates in 15 districts catering to 55% of the geographical area.
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Speaking at the Inauguration ceremony of AG&P Pratham’s CNG station, Mr. Hardeep Singh Puri, Hon’ Minister of Petroleum and Natural Gas appreciated AG&P Pratham’s efforts in building natural gas powered infrastructure in the country. The Minister welcomed the Japanese investment in Indian CGD sector and sought more Japanese investment in development of gas infrastructure in India. He talked about the technological advancement in the gas sector in Japan and expressed his hope that the collaboration with AG&P Pratham would ensure bringing Japanese technology into Indian operations. He said that this is testament of the commitment of the Government under the leadership of Hon’ble Prime Minister Shri Narendra Modi to provide people with convenient and environment friendly energy options. He also said that the availability of CNG and PNG in the region opens a new chapter in the lives of the community and further said that very soon every household in Hassan will have PNG connects. He also talked about Governments’ commitment to phased increase in bio gas blending on CNG and PNG as per recent policy initiatives. He further said that Shri Narendra Modi led Government is working on increasing FDI and improve international collaborations and in developing India as an energy hub.
Shri Abhilesh Gupta, Managing Director and CEO, AG&P Pratham, informed that AG&P Pratham has already invested around 4000 Crores in its GAs and further commitment of another 15000 Crores in the next 6-7 years. He said that we are ready to provide PNG connections to about 2 lakh household in the next few months. Under the visionary leadership of the Hon’ble Prime Minister and the able guidance of the Hon’ble Minister the Government has realised the dream of One Nation One Grid and which ensure gas is delivered far-flung areas with optimised logistics costs and removing tax inefficiencies. Our network spans 3400 kms of MDPE pipelines, 900 kms of steel pipelines and 300 CNG Stations. He thanked Dr. Anil Kumar Jain, Chairman, PNGRB for the passion with which PNGRB has been driving creation of CGD infrastructure across the country.
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Natural Gas/ Pipelines/ Company News
Cairn oil & gas submits field development plan for gas production from Jaya block
Cairn India employees work at a storage facility for crude oil at Mangala oil field at Barmer in the desert Indian state of Rajasthan | Photo Credit: PARTH SANYAL
Cairn Oil & Gas on Thursday said that it has submitted the Field Development Plan (FDP) to start gas production from the open acreage licensing program (OALP) block in Gujarat’s Bharuch district.
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In August 2021, the company, part of the Vedanta group, notified the gas and condensate discovery of Jaya in its onshore OALP block in Gujarat.
“Through exploration and appraisal successes, Cairn has now submitted a FDP to produce more than 2,000 barrels of oil equivalent per day (boepd) initially,” the company said.
This field has the potential to contribute to the company’s goal of doubling production capacities and driving energy aatmanirbharta for India. This will be the first FDP submitted in OALP regime, among 144 blocks awarded under eight OALP rounds by the government to various companies, it added.
Cairn Oil & Gas’ Deputy CEO Steve Moore said, “We are delighted to have progressed to Jaya discovery to its FDP and ready to begin production from Jaya block. This block in Gujarat was one of the initial discoveries for Cairn under India’s OALP, and we believe it will contribute to India’s energy requirements.” Jaya field, during its appraisal phase, started testing gas evacuations in an innovative manner through truck-mounted compressed natural gas (CNG) kits providing CNG to nearby gas stations. This is the first-of-its-kind facility where sales through a CNG cascade system is being done by an E&P operator from an exploration well.
It has enabled Cairn to minimise gas flaring in line with its decarbonisation vision while allowing appraisal. This gas sales through cascading served the dual aim of monetising gas as well as fulfilling the nation’s energy requirements.
Cairn has also signed a commercial gas sales agreement for gas off-take.
The company has utilised advanced rock physics and seismic inversion technology to predict subsurface sweet spots in and around the Jaya area. A cluster of prospects has been identified which can be developed through tieback to the Jaya facility.
Through the FDP for Jaya, Cairn has nurtured a new asset in the western region that will support holistic economic and sustainable development. New exploration and production will continue to be the benchmarks of Cairn’s operations to drive energy security for India.
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Prime Minister to lay foundation stone for Krishnagiri-Coimbatore section of GAIL pipeline project
Prime Minister Narendra Modi will lay the foundation stone for the 294-km-long Krishnagiri-Coimbatore section of the Kochi- Kuttanad- Bengaluru- Mangaluru Pipeline (KKBMPL) project at Tiruchi on Tuesday, Gas Authority of India Limited (GAIL) Executive Director (operation and maintenance) for southern region S. Mowar has said.
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Speaking to reporters here on Monday, Mr. Mowar said that the Central government envisions raising the share of natural gas in the primary energy mix from the current 6.7% to 15% in the coming years. GAIL is overseeing the implementation of the natural gas pipeline project from Krishnagiri to Coimbatore, constituting a key segment of the KKBMPL project, with an anticipated project cost of ₹2,187 crore. This initiative aims to provide eco-friendly and affordable fuel to industries, households, and the transport sector in Tamil Nadu and Karnataka. The pipeline, boasting a capacity of four million metric standard cubic meters per day (MMSCMD), is targeted for completion by November 2024. The pipeline route is predominantly aligned with highways, Mr. Mowar added.
Explaining the benefits of the project, Mr. Mowar said that the Krishnagiri to Coimbatore pipeline will traverse through Krishnagiri, Dharmapuri, Salem, Namakkal, Erode, Tiruppur, and Coimbatore districts, thereby connecting Tamil Nadu to the National Gas Grid. This strategic infrastructure project is expected to create employment opportunities and serve as a catalyst for the development of the region, particularly in industries like fertilizer and petrochemical complexes.
With the expansion of the National Gas Grid, branch lines connecting cities and towns along the route will facilitate access to environment-friendly fuel for industries, CNG for vehicles, and PNG for households.
Additionally, it will contribute to the reduction of vehicular carbon emissions and provide uninterrupted access to clean natural gas. This pipeline project is slated to provide approximately 6.5 lakh mandays of direct or indirect employment during the construction phase. The completion of the Krishnagiri-Coimbatore pipeline will connect nine districts in Tamil Nadu to clean natural gas. It is anticipated to reduce around 2.7 lakh tonnes of CO2 emissions annually. It provides 24×7 PNG to approximately 59.2 lakh consumers and an additional 1,198 CNG stations, Mr. Mowar added.
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ONGC seeks partners to cut gas flaring, zero methane emission by 2030
According to the International Energy Agency, India’s share in global primary energy consumption is expected to rise to 9.8 per cent by 2050.
New Delhi: India’s top oil and gas producer ONGC is seeking global technology partners to cut gas flaring and achieve zero methane emission by 2030 as part of its ambitious decarbonisation plan, its chairman Arun Kumar Singh said on Monday.
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Oil and Natural Gas Corporation (ONGC) has substantially cut gas flaring — burning of methane gas that is produced when oil is extracted from below surface — and would look to bring it down to nil as part of its environmental commitments.
In a post on LinkedIn, Singh said India’s role in the global energy landscape is progressively becoming pivotal, and is likely to account for 25 per cent of global energy demand growth over the next two decades.
According to the International Energy Agency, India’s share in global primary energy consumption is expected to rise to 9.8 per cent by 2050.”India’s share in cumulative global green-house-gas (GHG) emissions has been only 4 per cent, and current emission is 7 per cent, despite its population share of 16-17 per cent,” he said.”As a responsible corporate citizen of the world, we are fully aware of our obligation towards the mother planet, which is shared by developing and developed world alike. Accordingly, our nation is chasing a paradigm shift in energy consumption, with a focus on cleaner, greener, and sustainable alternatives.”With increasing energy demand, the commitment to decarbonisation is stronger than ever.”ONGC has made significant contributions in reducing gas flaring in our exploration and production (E&P) operations, aligning with our environmental commitments; we have consistently worked to bring it lower and lower, and we aim to bring avoidable flaring down to zero by 2030…Similarly, substantive reduction has been achieved in the area of methane emission, and we aim to bring it down to zero level by 2030,” he said.
Singh said ONGC uses a lot of gas to generate electricity as well as meet compression and other process needs of an oil and gas field. By 2028, this gas is intended to be replaced with green power wheeled to installations as far as 160 km from the west coast. The gas thus freed will be sold to industries like fertiliser and power plants.”We envisage to wheel green electricity to our Mumbai Offshore fields on the Arabian Sea, replacing natural gas, currently being used to drive power devices at process platforms,” he said.
Companies around the globe have pledged to slash down methane emissions by 30 per cent from 2020 levels by 2030. Methane, which is a more potent greenhouse gas than carbon dioxide, tends to leak into the atmosphere.
This is sometimes deliberate when companies flare the gas that comes alongside crude oil, due to lack of consumption markets. It also can leak undetected from drill sites, gas pipelines and other oil and gas equipment.
Controlling methane, which has been rising in atmospheric concentration for decades, is seen as one of the easiest and cheapest ways to make an immediate impact on global greenhouse gas emissions.”Collaboration and innovation are the key here. Realising this need, we extend an invitation to all the innovators offering superior technology and are ahead on the learning curve relating to this goal of nil methane emission and zero avoidable flaring,” he said.
He went on to ask technology innovators to write to ONGC on possible solutions to the flaring and methane emission problem.
Flaring, which used to be done in the past because of lack of customers for gas, has been reduced by almost 80 per cent, he said.
Crude oil pumped out of ground can easily be transported in trucks but to take gas from remote well locations to industries requires pipelines.
Sometimes, the amount of gas coming out with oil is so low that laying a pipeline becomes uneconomical.
ONGC used to flare 14-15 million standard cubic metres per day, but this has now come down to around 2 per cent.
Gas flaring reduction and zero methane emissions are part of ONGC’s decarbonisation drive which will also see the company putting up 10 gigawatt of plants to generate electricity from solar and wind, and constructing a 1 million tonnes per annum green ammonia plant on the west coast.
ONGC is also looking at setting pump storage projects at river dams to meet electricity demand at night when solar power cannot be generated. It will also set up compressed biogas plants to convert agri waste into gas that can be used to generate electricity, make fertiliser or turned into CNG to run automobiles.
The company, which accounts for about two-thirds of India’s oil production and about 58 per cent of gas, plans to invest Rs 2 lakh crore on clean energy projects to meet its 2038 net-zero carbon emissions goal.High pressure gas valued at Rs 816.08 crore was flared in Mumbai High field — the mainstay fields of ONGC — during 2012-20, according to a CAG report released in December 2021.During 2012-13 to 2019-20, a total of 1,227.343 million metric standard cubic metres of high pressure gas valued at Rs 1,021.08 crore was flared, according to the CAG report.
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Rashmi Govil to be next Director (HR) of IOC
With nearly three decades at IOC, Rashmi Govil’s extensive experience spans various HR domains, strategic initiatives, and pivotal policy revisions amid the pandemic. Rashmi Govil, a senior HR executive at Indian Oil Corporation (IOC), is set to be next Director (Human Resources) of the state-owned firm. Her name for the job was recommended by the Public Enterprises Selection Board (PESB), according to a notification by the government headhunter.
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PESB interviewed 11 candidates, including five from IOC, before recommending Govil for the job, the notification showed.
She is presently Executive Director (HRD & ER) in IOC.
Govil will replace Ranjan Kumar Mohapatra, who was in May denied an 8-month extension of service till his superannuation age.
Govil joined IOC in 1994 and has been with the company for almost three decades. An alumna of Bundelkhand University, she is an MBA with specialization in HR and a PG Diploma in Finance.
The challenging industrial relations experience in a refinery environment in early years of her career helped her develop a deep understanding of employee relations.
Over the years, she has worked in various segments of HR including industrial relations, compensation management, performance management, staffing recruitment, policy formulation, succession planning, systems management, and audit.
She has led various strategic initiatives at the corporate office of IOC.
She was responsible for roll out of enterprise-wide SAP solutions in HR and multiple landmark settlements with the collectives including long-term wage settlements with 25 unions of IOC.
During COVID times, she revisited and revised numerous policies making them in sync with the needs of the occasion.
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India Inks Contracts for 13 Hydrocarbon Blocks
India’s Petroleum and Natural Gas Ministry has signed contracts for 13 hydrocarbon blocks opened for bidding in the last two years.
Of the new contracts, 10 came from the 2023 Open Acreage Licensing Policy (OALP) Bid Round VIII, which offered 34,364 square kilometers (13,268.02 miles). Three were under the 2022 Special Coalbed Methane (CBM) Bid Round, which opened 5,817 square kilometers (2,245.96 miles).
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In India the OALP allows companies to carve out development areas of their choice based on resource data at the National Data Repository (NDR), which stores exploration and production research results for Indian sedimentary basins. They then submit expressions of interest (EOIs), in a process done any time without waiting for a bidding round. These EOIs form the basis of biannual OALP bidding rounds.
CBM bidding meanwhile is for producers seeking to extract natural gas from coal.
Under the eighth round of the OALP, 13 companies made offers for the 10 blocks put forward. Four companies emerged successful, committing a total of $233 million for exploration work, the government’s Press Information Bureau (PIB) said in a recent press release.
The 10 blocks are “spread across 9 Sedimentary Basins and included 2 Onland blocks (both in Category-I Basin), 4 Shallow Water blocks (1 in Category-I and 3 in Category II/III Basins), 2 Deep Water blocks (both in Category II/III Basins) and 2 Ultra Deep-Water blocks (1 in Category-I and 1 in Category-II Basin)”, the media announcement stated.
In the Special CBM round, 16 blocks were offered, spread across seven states. Only three blocks got bidders. Of the six companies that made submissions, only two won awards, for a total area of 717 square kilometers (276.84 miles). Pledges for exploration work from the successful bidders totaled $7.4 million.
Simultaneously the petroleum ministry opened applications for the ninth round of the OALP. Twenty-eight blocks straddling 136,596 square kilometers (52,740.01 miles) are on offer. These blocks already received expressions of interest in 2022 and 2023, the ministry’s Directorate General of Hydrocarbons said in a separate news release.
Many of the Round 9 offshore blocks are in hydrocarbon-rich areas earlier inaccessible for exploration due to restrictions by different agencies, according to the PIB statement.
Bidders have until February 29 to make submissions.
“[I]t is estimated that after award of blocks under forthcoming OALP-IX and X Bid Rounds, about 5,60,000 Sq. Km. area [16 percent of Indian sedimentary basins] will come under exploration by end of year 2024”, the PIB news release said.
“[V]ast offshore acreage of more than 1 Million Sq. Km. [386,102.16 miles] has been made available in recent past for E&P [exploration and production] operations which were earlier so called ‘No-Go’ areas”, the PIB said citing Petroleum and Natural Gas Minister Shri Hardeep Singh Puri. Only 10 percent of Indian sedimentary basins are under active exploration, the minister said.
“There is also continued focus on greater transparency and streamlined procedures”, the PIB added.
India adopted the Hydrocarbon Exploration and Licensing Policy (HELP) in March 2016 with reforms that include lower royalty rates, marketing and pricing freedom and a revenue sharing model.
“Now, with the award of 10 more blocks under Round-VIII, a total of 144 exploratory blocks have been awarded under HELP regime covering an area of 2,42,055 Sq. Km [93,457.96 miles]”, the PIB said.
“Several initiatives have been taken by the Government for making available good quality data of Indian Sedimentary Basins to investors, such as National Seismic Program (NSP) in Onshore areas, EEZ [exclusive economic zone] Survey in Offshore areas, opening of Andaman Basin, upgradation of NDR, etc.”, it added.
“Other initiatives planned are Mission Anveshan Project (Part II of NSP), Continental Shelf Survey, drilling of Stratigraphic Wells and Hydrocarbon Resource Reassessment Study”.
“Investors outreach program has also been aggressively taken up through organizing Investors Meet at prominent global locations and International Conferences”, the PIB said.
“Several IOCs [international oil companies] have visited NDR and purchased large volume of E&P Data for analysis”.
All approvals for the exploration and production sector have also been made online, it noted.
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Policy Matters/ Gas Pricing/ Others
Govt reduces natural gas price to $7.82/mmBtu for January, amidst global price dip
“The price of domestic natural gas for the period 1st January 2024 to 31st January 2024 is notified as $7.82/MMBTU on Gross Calorific Value (GCV) basis,” the PPAC said in a statement.
New Delhi: The Central government has reduced the price of domestically produced natural gas to $7.82 per million British thermal units (mmBtu) for January, a significant cut from $8.47 per mmBtu in the previous month, according to a statement from the Petroleum Planning & Analysis Cell (PPAC).This price revision applies to gas produced from fields classified as ‘difficult’, predominantly under private operation.
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“The price of domestic natural gas for the period 1st January 2024 to 31st January 2024 is notified as $7.82/MMBTU on Gross Calorific Value (GCV) basis,” the PPAC said in a statement.
In contrast, the price for gas produced from the nomination fields of the state-controlled Oil and Natural Gas Corporation (ONGC) and Oil India Limited (OIL) remains at a capped price of $6.5 per mmBtu.
Following the Union Cabinet’s approval of a new gas pricing regime in April last year, domestic natural gas prices in India have been linked to the Indian crude oil basket, adjusting monthly.This policy shift, recommended by the Kirit Parikh-led committee, connects domestic gas prices to global crude oil prices.
Under the new guidelines, natural gas prices are set at 10% of the monthly average of the Indian crude basket, which includes Dubai and Oman (sour) and Brent Crude (sweet) oil prices.
The nomination fields, assigned to ONGC and Oil India before 1999, have a fixed gas price cap at $6.5 an MMBTU.
The decline in gas prices is expected to benefit industries such as fertilizers and gas-based power
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Independent panel to address grievances related to auction of domestic natural gas
The government has set up an ‘independent oversight committee’ to address the grievances of buyers and sellers of domestic natural gas in auctions conducted by empanelled agencies.The five-member committee formed by the Directorate General of Hydrocarbons (DGH) would be chaired by MD Gupta.
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“The committee shall monitor and review the performance of empanelled agencies periodically and examine complaints or grievances received from a seller or buyer of natural gas against the empanelled agency and submit their recommendation(s), if any, to the competent authority,” DGH said in a notification on its website.Locally produced natural gas that can be sold at market rates subject to a government-set price cap is usually auctioned to buyers.
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Global Biofuel Alliance may not see further expansion soon, says NITI Aayog chief
Further, the framework of the alliance is likely to focus on increased private investments in the clean energy segment to be able to achieve the target of net zero emissions. India is not expecting any other country to join the Global Biofuel Alliance immediately, the country’s G20 Sherpa and former NITI Aayog chief executive Amitabh Kant told FE. However, participation from other countries is expected once the relevant recommendations are implemented, he added.
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“Work is being done in several areas. We are taking forward the implementation of all the recommendations under G20 including green development, circular economy, and tripling renewable energy,” Kant said. Further, the framework of the alliance is likely to focus on increased private investments in the clean energy segment to be able to achieve the target of net zero emissions.
“India’s push for G20 has advised multilateral development banks to shift their approach by focusing on three key aspects – making private capital mobilization as the central element of the sustainable development strategy, supporting governments in reducing policy and regulatory risks to private investment and aligning their financial product offering to private capital market gaps,” Kant said while addressing the gathering at the “Climate Financing” conference organized by Ease of Doing Business.
The Global Biofuel Alliance, launched during the G20 summit in September 2023 under India’s presidency, presently has 21 member countries with 12 international organizations and aims at worldwide development and deployment of biofuels by offering capacity-building exercises across the value chain, technical support for national programs, and promoting policy lessons-sharing.
The alliance which includes the US and Brazil, the top consumers and producers of biofuels, can help India reduce its dependency on crude oil imports by way of technology transfer for enhanced production of biofuel domestically. However, the major producers of crude oil – Russia and Saudi Arabia have so far stayed out from joining the alliance and so has China.
The government has been working towards the promotion of compressed biogas as an alternative source of energy to reduce its dependence on fossil fuels for quite some time now. In addition to catalyzing the formation of the Global Biofuel Alliance, the government has now mandated 5% blending of CBG with compressed natural gas and piped natural gas by FY29.
Union minister for petroleum and natural gas Hardeep Singh Puri had earlier said that the global biofuels market is set to jump from its current value of $92 billion to $200 billion post the launch of the alliance.
Indian Biogas Association’s Chairman Gaurav Kedia had told FE that the alliance may come out with the entire framework for the Global Biofuel Alliance this year and are already consulting different organizations for the same. “There might be a little more emphasis on the liquid side (ethanol) to start with,” he had said.
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LNG Use / LNG Development and Shipping
India’s Petronet LNG to extend LNG deal with Qatar beyond 2028
Qatar continues global LNG dominance with strategic long-term agreements
Petronet LNG Ltd, India’s leading natural gas importer, is expecting to sign an agreement with Qatar to extend its liquefied natural gas (LNG) supply deal beyond 2028. The development was recently revealed by India’s Oil Secretary, Pankaj Jain.
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The pivotal deal will secure a sustained and reliable source of LNG for India beyond 2028, marking a significant development in the country’s energy landscape.
Jain confirmed on Wednesday that Petronet LNG and Qatar are in the final stages of negotiations. He expressed confidence in the imminent signing of the agreement. The extension would ensure the continuation of a longstanding partnership between the two nations, fostering India’s energy security.
Under the current long-term agreement, Petronet LNG committed to importing 7.5 million metric tons of LNG annually from Qatar. The extension of this deal will reinforce India’s position in the energy market. Moreover, it aligns with the nation’s growing demand for natural gas.
Qatar’s strategic approach
Qatar, one of the world’s largest LNG exporters, has consistently favored entering into long-term agreements with its global clientele. The country had set a deadline until the end of 2023 for Indian customers to engage in negotiations regarding potential extensions or renewals of existing agreements beyond 2028. Petronet LNG, one of the major players, could benefit from Qatar’s commitment to ensuring a stable and extended supply.
Qatar’s proactive approach to securing long-term agreements has been evident in recent months. It has inked 27-year deals with prominent global entities, including China’s Sinopec and China National Petroleum Corporation (CNPC). Moreover, it recently secured agreements with European giants Shell, TotalEnergies, and Eni. These agreements solidify Qatar’s standing as a major player in the global LNG market. These European majors are also minority shareholders in various LNG production trains of the North Field expansion project.
North Field expansion project
Qatar’s groundbreaking ceremony in October for the North Field expansion project, the world’s largest LNG endeavor, underlines the nation’s commitment to expanding its export capacity. Qatar is set to play a crucial role in meeting global LNG demand. Thus, it seeks to add 48 million tons per annum (mmtpa) to its production capabilities by 2027.
In July last year, Qatar’s Minister of State for Energy Affairs and the President and CEO of QatarEnergy, Saad Sherida Al-Kaabi, said, “40 percent of all the new LNG that will come to the market by 2029, when all our projects are up and running, is going to be from QatarEnergy.”
https://economymiddleeast.com/news/india-petronet-lng-extend-deal-qatar/
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India’s GAIL signs 10-yr LNG purchase deal with Vitol
State-run GAIL (India) Ltd GAIL.NS Friday said it has signed a 10-year liquefied natural gas (LNG) import deal with trader Vitol to buy about 1 million metric tons per year (tpy) of the super-chilled fuel from 2026.
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Indian companies are investing billions of dollars to build natural gas infrastructure and are scouting for long-tern LNG imports deals as the nation wants to raise the share of natural gas in its energy mix to 15% by 2030 from the current 6.3%.
Vitol will deliver LNG from its global LNG portfolio to GAIL at various locations in India, GAIL said in a statement.
Gas consumption in India would rise to over 500 million standard cubic metres a day (mmscmd) by 2030 from the present 155 mmscmd, oil minister Hardeep Singh Puri said this week.
GAIL has an LNG portfolio of around 14 million tpy comprising supplies from countries including the USA, Qatar, Australia and Russia, according to its 2022/23 annual report.
GAIL is continuing negotiations with others for long term deals, its head of marketing, Sanjay Kumar, said.
The company plans to add 7 million to 8 million tpy of LNG to its portfolio by 2030, its head of finance said last year.
GAIL, which operates a 5 million tpy LNG plant in Western Maharashtra State, has also leased space at other Indian terminals. It is scouting for a 26% stake in a U.S.-based LNG plant to source 1 million tpy of LNG for 15 years.
It is also in talks with Abu Dhabi National Oil Co and Russian LNG producer Novatek NVTK.MM, and Qatar to source LNG.
https://www.hellenicshippingnews.com/indias-gail-signs-10-yr-lng-purchase-deal-with-vitol/
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Electric Mobility/ Hydrogen/Bio-Methane
Cabinet approves signing of MoU between India and Guyana on cooperation in the hydrocarbon sector
The Union Cabinet chaired by the Prime Minister, Shri Narendra Modi has approved the signing of Memorandum of Understanding (MoU) between the Ministry of Petroleum & Natural Gas, Government of India and the Ministry of Natural Resources, Republic of Guyana on cooperation in the hydrocarbon sector.
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Details of the MoU:
The proposed MoU covers the complete value chain of hydrocarbon sector including sourcing of crude oil from Guyana, participation of Indian companies in Exploration and Production (E&P) sector of Guyana, cooperation in the areas of crude Oil refining, capacity building, Strengthening bilateral trade, collaboration in natural gas sector, collaboration in developing regulatory policy framework in oil & gas sector in Guyana; Cooperation in the area of clean energy including biofuels as well as renewables sector including solar energy etc.
Impact:
The MoU on cooperation in hydrocarbon sector with Guyana will strengthen bilateral trade, foster investment in each other countries and help diversifying source of crude oil, thus augmenting the energy & supply security of the country. It will also provide opportunity to Indian company to participate in E&P sector of Guyana, gaining experience by working with global oil & gas companies in upstream projects, thus fostering the vision of “Aatmanirbhar Bharat”.
Implementation strategy and targets:
This MoU shall enter into force on the date of its signature and will remain in force for a period of five years and shall be automatically renewed thereafter on a quinquennium basis unless either Party gives the other Party a written notice three months in advance of its intention to terminate this Understanding.
Background:
In recent times, Guyana has gained significant salience in the oil & gas sector becoming the world’s newest oil producer. The new discoveries of 11.2 billion barrels of oil equivalent, amounts to 18% of total global Oil & Gas discoveries and 32% of discovered oil. As per OPEC World Oil Outlook 2022, Guyana is projected to see a significant ramp-up in production, with liquids supply growing from 0.1 mb/d in 2021 to 0.9 mb/d in 2027.
Further, as per BP Statistical Review of World Energy 2022, India is the world’s 3rd largest energy consumer, 3rd largest consumer of oil and 4th largest refiner and the fastest-growing major economy with rising energy needs. BP Energy Outlook and International Energy Agency estimate that India’s energy demand would grow at about 3% per annum till 2040, compared to the global rate of 1%. Further, India is likely to account for approximately 25-28 per cent of the global energy demand growth between 2020-2040.
With a view to give a further impetus to ensure energy access, availability, affordability to citizen underpinned by energy security of the country, India is focusing on fostering new partnership in hydrocarbon sector, both through diversification of crude oil sources and through acquiring quality overseas assets. This dilutes dependencies on a single geographical/economic unit and increase India’s strategic maneuverability.
Noting the significance of Guyana and given the renewed momentum to the bilateral relationship in hydrocarbon sector, and the number of possible areas of cooperation, it is proposed to enter into an MoU with Guyana on cooperation in the hydrocarbon sector.
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GAIL (India) and TruAlt Bioenergy Ink Deal for India’s Second CBG Plant
In a significant stride towards sustainable energy solutions, GAIL (India) Limited and TruAlt Bioenergy have officially signed a partnership agreement to establish India’s second Compressed Bio-Gas (CBG) plant. The deal, sealed during a ceremony at GAIL’s headquarters, marks a crucial step in the nation’s commitment to green and renewable energy sources.
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The collaboration aims to contribute to India’s ambitious target of achieving 15% blending of natural gas with CBG by 2030, reducing the carbon footprint and dependency on traditional fossil fuels. The project is aligned with the government’s vision for a cleaner and greener energy landscape, promoting the use of bioenergy as a sustainable alternative.
GAIL, a leading natural gas company in India, brings its extensive expertise in the energy sector to the partnership. With a robust infrastructure and a track record of successful ventures, GAIL is well-positioned to facilitate the development and operationalization of the CBG plant. The company’s commitment to environmentally friendly initiatives underscores its dedication to a sustainable energy future.
TruAlt Bioenergy, a pioneering force in the bioenergy sector, is set to provide cutting-edge technology and know-how for the production of Compressed Bio-Gas. Leveraging their experience in developing similar projects globally, TruAlt is poised to play a pivotal role in making this venture a success. The collaboration is expected to bring forth innovative solutions for bioenergy production, setting new benchmarks in the field.
The CBG plant will be strategically located to optimize feedstock availability and distribution, ensuring a seamless integration into the existing energy infrastructure. By utilizing organic waste materials, the plant will produce high-quality biofuel, contributing to waste management while simultaneously generating a clean and renewable energy source.
Mr. Manoj Jain, Chairman and Managing Director of GAIL (India) Limited, expressed enthusiasm about the partnership, stating, “This collaboration with TruAlt Bioenergy represents a significant leap towards achieving India’s renewable energy goals. GAIL is committed to pioneering sustainable solutions, and this venture aligns perfectly with our vision for a greener and cleaner tomorrow.”
Dr. Neha Gupta, CEO of TruAlt Bioenergy, echoed these sentiments, saying, “We are excited to partner with GAIL in this transformative project. India holds immense potential for bioenergy, and our expertise combined with GAIL’s infrastructure will create a model for sustainable energy production.”
The joint efforts of GAIL (India) Limited and TruAlt Bioenergy in establishing India’s second CBG plant highlight the nation’s commitment to fostering innovation in the energy sector. As the world grapples with climate change, such initiatives become crucial steps towards a more sustainable and eco-friendly future.
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UltraTech Cement pioneers green mobility with five electric trucks
The company’s environmental movement entails transporting clinker from UltraTech’s integrated cement manufacturing facility in Madhya Pradesh to the grinding unit at Dhule Cement Works in Maharashtra.
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UltraTech Cement Ltd, India’s largest cement and Ready-Mix Concrete (RMC) company, has taken an important move toward green mobility through the introduction of five electric trucks to transport clinkers. This environmentally friendly initiative entails transporting clinker from UltraTech’s integrated cement manufacturing facility in Madhya Pradesh to the grinding unit at Dhule Cement Works in Maharashtra.
Three charging stations have been set up by the company, one at each of its manufacturing facilities and one on route, to guarantee the dependability of this environmentally friendly mode of transportation. It is anticipated that switching to these electric trucks from trucks powered by fossil fuels will cut transportation emissions by about 680 metric tonnes of CO2 per year.
UltraTech Cement Limited’s managing director, K C Jhanwar, reaffirmed the company’s dedication to promoting sustainability throughout all aspects of its business. In addition to the use of LNG and compressed natural gas (CNG) trucks in their operations, he emphasised the accomplishments of the electric truck pilot programme.
As part of the Government of India’s eFAST initiative, the company has committed to supporting sustainable transportation, with the goal of integrating 500 electric trucks and 1000 CNG/LNG vehicles into its operations by June 2025. The company is actively working to replace conventional diesel vehicles with CNG and LNG trucks in partnership with logistics partners.
The company introduced green logistics in the form of CNG and LNG vehicles in 2021 and 2022, respectively. With coordinated efforts with logistic partners, the company currently runs more than 390 CNG trucks and 50 LNG trucks across 17 manufacturing units.
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EV producer VinFast invests in India’s Tamil Nadu
Vietnamese auto manufacturer VinFast will invest $2bn in south India’s Tamil Nadu state to develop the electric vehicle (EV) sector, including building a plant to produce 150,000 units/yr. VinFast, a subsidiary of private-sector firm Vingroup, and the Tamil Nadu state government have signed an initial agreement, with VinFast investing $500mn in a first phase to set up an integrated EV facility that will be built over five years.
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Construction of the plant, located in Thoothukudi district, is likely to begin this year, VinFast said on 6 January. Completion timelines were undisclosed. VinFast and the state government did not outline what the remaining $1.5bn will be spent on.
The Tamil Nadu government announced an EV policy in February 2023 to transform the state into a preferred destination for EV manufacturing in southeast Asia.
“We believe that investing in Tamil Nadu will not only bring considerable economic benefits to both parties but will also help accelerate the green energy transition in India and the region,” said VinFast’s deputy chief executive of sales and marketing Tran Mai Hoa.
Tamil Nadu is a major automobile market with the third-largest number of vehicles in India. Tamil Nadu aims to generate 500bn rupees ($6.02bn) of investment in EVs over a period of five years from 2023, it had said in February last year.
The policy declares six cities — Chennai, Coimbatore, Tiruchirappalli, Madurai, Salem and Tirunelveli — as pilot cities for EV adoption. The Tamil Nadu government will develop EV charging infrastructure in these six cities through partnerships between state-controlled and private-sector firms. The state will also provide subsidies for new and expansion projects in the production of EVs, EV components and charging infrastructure.
The EV industry in India is fast growing, with production forecast at 10mn units/yr by 2030, government think tank Niti Aayog adviser Sudhendu Sinha said in September last year.
Indian EV sales have been robust despite a subsidy cut in June last year. Indian manufacturers sold 140,842 EVs in December, down by 8.2pc from a revised 153,441 units in November but up by 42pc from 99,480 units in December 2022, data from government website Vahan show. The Indian government aims for EVs to comprise 30pc of all new vehicle sales by 2030.
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INTERNATIONAL NEWS
Natural Gas / Transnational Pipelines/ Others
US: BLM Approves Oil and Gas Pipeline Right-of-Way Assignment in Kern and San Bernardino Counties
NEEDLES, Calif. – The Bureau of Land Management has approved the assignment of an existing Mineral Leasing Act right-of-way grant held for a natural gas pipeline by El Paso Natural Gas Company (EPNG) to Cadiz Real Estate, LLC (Cadiz) as part of a change of ownership. The assignment involves a 71-mile portion of an existing 30-inch diameter, buried gas pipeline extending 217 miles between Cadiz Valley in San Bernardino County and Wheeler Ridge, near Bakersfield, in Kern County.
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“The BLM carefully reviewed public comments and used that input to shape the decision,” said BLM Needles Field Manager Mike Ahrens. “The BLM added terms and conditions to make clear this decision is limited to the assignment of EPNG’s existing rights and may not be used for transporting anything other than natural gas.”
Approval of the assignment follows a 15-day public comment period and formalizes the change in ownership, authorizing ongoing pipeline maintenance and the transport of natural gas consistent with the Mineral Leasing Act of 1920 without conveying any additional rights.
The segment of the existing oil and gas pipeline has not been used for more than 10 years. Although Cadiz previously expressed an interest in converting the pipeline to convey water, this assignment would not give Cadiz any future right or guarantee to utilize the right-of-way for such a purpose. Any future proposal to convert the pipeline for other uses would need to be considered under the National Environmental Policy Act and other environmental laws and would include opportunities for public comment and community outreach.
The map and other planning documents are available on the BLM National NEPA Register. For additional information about this project, contact BLM Realty Specialist Russell Hansen at jhansen@blm.gov.
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Australia: Shell ready to embark on seabed survey activities at natural gas field
Shell Australia, a subsidiary of oil major Shell, has tucked a green light for its environment plan (EP) under its belt from the country’s offshore regulator for a seabed survey on the Crux natural gas field off the coast of Western Australia.
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The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) confirmed the approval of Shell’s environment plan in December 2023, enabling the oil major to undertake the Crux seabed survey within production licenses AC/PL1 and WA-33-PL.
This seabed survey will encompass a geophysical survey and a geotechnical survey to investigate sub-seabed geological conditions to understand conditions at the proposed pipeline pipelay initiation and the pipeline end manifold (PLEM) locations for the Crux pipeline.
In addition, the aim is also to check geological conditions for proposed pipeline end terminations (PLET) foundations at both the Crux and Prelude ends of the proposed Crux pipeline; identify potential seabed debris and obstructions; identify and map the nature and distribution of seabed surface types along potential pipeline routes; and accurately measure water depth and map seabed topography.
The Crux seabed survey will be carried out in Commonwealth and Ashmore Cartier marine waters, 200 km offshore northwest Australia and 460 km north-northeast of Broome, in 160 m to around 260 m from mean sea level (MSL) water depth. This is expected to take one week.
In a worse-case scenario, the survey could take up to 30 days which accounts for unforeseen circumstances and potentially more survey activities. The survey is currently planned to occur within a single campaign in 2024.
The Shell-operated Crux development, sanctioned in May 2022, is located in Commonwealth waters in the northern Browse Basin, 190 kilometers offshore northwest Australia and 620 km northeast of Broome, in approximately 165 meters of water depth.
The Crux joint venture, which comprises Shell Australia as the operator and SGH Energy as its joint venture partner, is progressing the project. The first environmental approval for Crux was the Crux Offshore Project Proposal (OPP), which was accepted in August 2020 by NOPSEMA.
According to Shell, the Crux gas field has been identified as a source of backfill gas for the existing Prelude floating liquefied natural gas (FLNG) facility. As a result, Crux will have the capacity to supply the Prelude FLNG facility with up to 550 million standard cubic feet of gas per day (mmscfd).
The development of this project will consist of a platform operated remotely from Prelude while five wells are expected to be drilled initially. Moreover, an export pipeline will connect the platform to Prelude, around 160 kilometers southwest of Crux. Shell anticipates the first gas in 2027.
https://www.offshore-energy.biz/shell-ready-to-embark-on-seabed-survey-activities-at-natural-gas-field/
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Nigeria: Compressed Natural Gas Initiative: Minister Hails Private Sector
Nigeria’s Minister of Information and National Orientation, Mohammed Idris, has praised the private sector for its role in advancing the country’s compressed natural gas (CNG) initiative, which aims to reduce the dependence on imported fuel and lower greenhouse gas emissions.
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Idris spoke at the commissioning of a CNG plant built by ABG Group, a Nigerian conglomerate, in Abuja on Tuesday, January 2, 2024
He also witnessed the graduation of 40 CNG conversion technicians trained by the company.
According to the Minister, CNG is a more cost-effective and environmentally friendly alternative to premium motor spirits, commonly known as petrol, for powering vehicles.
He commended President Bola Tinubu for his vision and leadership in promoting CNG as a key component of Nigeria’s energy transition.
“The CNG is the future and it is therefore important for Nigerian entrepreneurs to seize advantage of government policy on the CNG by investing in the human and material assets required to grow its infrastructure across Nigeria,” Idris said.
He added that the government has allocated N100 billion to support the CNG initiative, which has also gained the backing of the Nigerian Labour Congress, the country’s largest trade union.
ABG Group’s chairman, Alhaji Bawa Garba, said his company is grateful to the president for his support and is committed to being a pioneer in the CNG sector. He said the CNG plant, which has a capacity of 50,000 cubic meters per day, will supply gas to about 5,000 vehicles daily.
“Our group is thankful to President Tinubu for the bold decision to adopt CNG. We are always a pioneering company, and our involvement in the CNG initiative is underscored by training multitudes of CNG conversion engineers across Nigeria,” Garba said.
CNG, which is mainly composed of methane, is a cleaner-burning fuel that can reduce carbon dioxide emissions by up to 25% compared to petrol, according to the International Energy Agency. CNG also costs significantly less than petrol in Nigeria, according to the Nigerian National Petroleum Corporation.
Nigeria has an estimated 203 trillion cubic feet of proven natural gas reserves, the largest in Africa and the ninth-largest in the world. However, most of the gas is flared or exported as liquefied natural gas, rather than used for domestic consumption.
The government hopes to change that by expanding the CNG infrastructure and creating incentives for vehicle owners to switch to CNG.
It has set a target of converting one million vehicles to CNG by 2027.
https://von.gov.ng/compressed-natural-gas-initiative-minister-hails-private-sector/
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Ukraine: Ukraine’s Strategic Gas Storage Capacity Eases Europe’s Winter Worries
European companies have been relying more on Ukrainian storage to hold natural gas and withdraw it from there once winter heating demand rose. Firms based in Europe have been withdrawing larger volumes of gas from Ukraine in recent weeks, per data from Argus Media reported by the Financial Times on Tuesday.
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Larger volumes of natural gas stored in Ukraine have helped European natural gas storage levels to keep between 85% and 90% so far this winter, analysts say.
“Ukraine is playing a key role for central and eastern Europe’s security of gas supply this winter,” Natasha Fielding, Argus Media’s head of European gas pricing, told FT.
European demand has been subdued in recent months due to slowing economic activity, but Europe still needs a lot of natural gas for space heating and power generation.
The EU reached its target to fill sites to 90% of capacity months ahead of the deadline on November 1, and hit full storage levels ahead of winter season proper.
So, energy firms have been storing growing volumes of natural gas in Ukraine’s storage facilities as the EU’s sites were nearing capacity.
Despite risks of potential hits due to the war, traders have started to store natural gas at storage sites in Ukraine, taking advantage of the lower costs and high available storage capacity. The commodity can be bought anywhere and sent to Ukraine via reverse flows in pipelines from Hungary, Slovakia, and Poland.
With the EU storage nearly full, Ukraine’s available capacity could help the bloc ease gas supply concerns ahead of the winter, Brussels-based think tank Bruegel said in an analysis in July.
In October, Ukraine’s Prime Minister Denys Shmyhal said that the country was ready to allow non-resident traders to use up to half of its natural gas storage capacity. Ukraine has 30 billion cubic meters (bcm) of underground storage capacity. As much as 12 to 15 bcm of this capacity could be allowed to be used by foreign traders to store gas, according to the prime minister.
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Canada: AltaGas Closes Pipestone Acquisition, Makes FID on Expansion
AltaGas Ltd. has closed the acquisition of several Pipestone natural gas assets in Montney from Tidewater Midstream and Infrastructure Ltd. AltaGas has also declared a positive final investment decision on the Pipestone Phase II expansion project, the Calgary-based company said in a news release. The acquired assets include the Pipestone Natural Gas Processing Plant Phase I and Phase II expansion project, the adjacent Dimsdale Natural Gas Storage Facility, the Pipestone condensate truck-in/truck-out terminal, and the associated gathering pipeline systems required to operate these assets.
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The Pipestone Phase II expansion project is now 100 percent contracted under long-term take-or-pay agreements with a combination of marquee independent and investment-grade producers, Altagas said, adding that all Pipestone Phase II customers who are existing Pipestone Phase I customers have also agreed to multi-year contract extensions, “further improving the long-term commercial profile of the Pipestone assets”.
The expansion project will be constructed on a fixed price turnkey basis for the majority of the capital costs, Altagas noted. The project will deliver critical gas processing and liquids handling capacity in the Pipestone region, which is one of the fastest growing liquids-rich natural gas developments in Canada, the company added.
Altagas said the Pipestone assets strengthen its midstream value chain through an expanded footprint in the Alberta Montney and provide meaningful long-term liquified petroleum gas (LPG) supply for the company’s global export platform.
“Closing this transaction and reaching a positive FID on Pipestone Phase II significantly strengthens our position in one of Canada’s most prolific resource plays”, Altagas President and CEO Vern Yu said. “This acquisition is consistent with our long-term strategy through adding long-life infrastructure assets with highly contracted take-or-pay and fee-for-service revenue. The transaction also diversifies our customer base, brings meaningful long-term LPG supply to our global exports platform, and provides long-term growth through the Pipestone Phase II expansion and has the potential for additional expansion phases”.
Tidewater received cash proceeds of $243.9 million (CAD 325 million) and approximately 12.47 million common shares of AltaGas for aggregate total consideration of approximately $499 million (CAD 665 million), the company said in a separate news release.
Tidewater said it plans to use the net proceeds from the transaction for general corporate purposes, including the repayment of amounts on its senior credit facility, which will provide an immediate improvement to its leverage profile and a reduction in cash interest costs.
“The closing of the transaction unlocks meaningful shareholder value and enhances our financial flexibility while significantly reducing our leverage”, Tidewater CEO Rob Colcleugh said.
The Pipestone Phase I facility is a modern sour deep-cut natural gas plant with 110 million cubic feet per day (MMcfpd) of processing capacity and 20,000 barrels per day (bpd) of liquids handling capacity located in the heart of Alberta Montney, according to AltaGas. The facility is currently 100 percent contracted with approximately 85 percent of the volumes coming from long-term take-or-pay contracts with credit-worthy customers. The facility includes 41.6 miles (67 kilometers) of natural gas gathering pipelines that are tied to key production regions and provide strategic egress connections to the Nova Gas Transmission Ltd. and the Alliance pipeline systems. The facility also includes the Pipestone condensate truck-in/truck-out terminal for liquids handling and value maximization.
Pipestone Phase II is a fully permitted, shovel-ready expansion project that will provide an additional 100 MMcfpd of sour deep-cut natural gas processing capacity and an additional 20,000 bpd of liquids handling capacity, according to AltaGas. Post-FID, the project is expected to be fully committed under firm take-or-pay and fee-for-service service agreements. Pipestone Phase II is expected to reduce operating costs and enhance run-time efficiencies for the broader Pipestone complex.
The Dimsdale natural gas storage facility is located east of the Pipestone I and II facilities. Its current working gas capacity of 15 billion cubic feet (Bcf) can be increased more than fourfold to 69 Bcf. Connected to Alliance and NGTL pipeline systems, the storage facility provides Pipestone customers with egress certainty and will be one of only three facilities able to serve the balancing needs of the Montney and Canadian LNG demand pulls mid-decade and will be the only integrated processing and storage facility in the Montney, AltaGas said. The facility is located upstream of the James River bottleneck points.
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Natural Gas / LNG Utilization
India’s LNG imports set for 7%-8% boost in 2024 on hopes of softer prices
India’s LNG imports in 2024 are expected to get a boost if prices stay pressured, with year-on-year inflows likely to grow up to 7%-8%, driven by higher demand in the power, industrial and transportation sectors while infrastructure spending also strengthens in a year due for national elections.
“India’s LNG imports will continue to increase, with an expected 8% year-on-year growth in 2024,” Ayush Agarwal, an LNG analyst at S&P Global Commodity Insights, said.
India currently has about 25 GW of gas-based power capacity installed. This translates to about 30 million-35 million mt/year of LNG demand, an LNG industry source based in Singapore said.
A few gas-based power units ran on domestic gas because of high LNG prices in recent years. That should change in 2024 because of the LNG price weakness, he added.
Over January-October, regasified LNG consumption by the power sector jumped 128% on the year, hitting 7.4 MMcm/d, while India’s peak demand grew 12.5% on the year during the same period to reach 243 GW, said Akshay Modi, a senior analyst covering South Asian natural gas, LNG and hydrogen at S&P Global.
“With the Platts JKM expected to fall below $10/MMBtu in 2024 summers, peak demand touching new highs and gas supporting renewables intermittency, we expect higher regasified LNG consumption for power sector to continue in 2024,” Modi said.
Demand spurts on low prices
India’s LNG consumption was set to jump if prices dropped below the $10/MMBtu mark, industry sources said.
The recent fall in prices has already sparked increased spot buying although some Indian buyers were exhibiting an appetite to consume LNG when JKM prices were relatively elevated, in the range of $15-$16/MMBtu.
Among recent market activity, Gujarat State Petroleum Corp. has bought a January-delivery cargo at $11.10-$11.20/MMBtu for delivery to Mundra.
In December, Indian Oil purchased a cargo at $11.20-$11.30/MMBtu for delivery to Ennore and GAIL bought a cargo at $11.40-$11.50/MMBtu for delivery to Dabhol in January.
Sources are also expecting higher utilization at the LNG terminals.
“Next year, we expect Dabhol terminal to be operational through the monsoon period as well … Dhamra will also be more utilized because of obligations to bring cargoes for GAIL, IOC,” one of the sources said.
After the commissioning of HPCL’s Chhara and GAIL’s Ratnagiri breakwater facility, the regasification capacity will likely rise to 52.5 million mt/year, S&P Global’s Modi said, adding that IOC’s Ennore-Tuticorin pipeline is also targeted for commission in 2024.
The country’s northeast gas grid commissioning plan has been granted an extension by the Petroleum & Natural Gas Regulatory Board until 2025. However, its progress will be crucial for the development of a gas-based economy in the region, Modi added.
Meanwhile, from mid-December 2023, Administered Pricing Mechanism, or APM, gas supplies to the transport and residential sector have been reduced to about 75% of demand compared to 88% earlier, Modi said, noting that the APM supply cut might see more city-gas entities tying up mid- to long-term offtake contracts.
The additional APM deficit for transport and domestic sector is around 3 MMcm/d and some of the volumes will likely be tied up by CGD’s in the expected upcoming ONGC auction in 2024, while the remaining will be catered through regasified LNG supplies, Modi added.
Source https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/lng/122823-indias-lng-imports-set-for-7-8-boost-in-2024-on-hopes-of-softer-prices#:~:text=Over%20January%2DOctober%2C%20regasified%20LNG,and%20hydrogen%20at%20S%26P%20Global.
Global LNG Development
Nigeria: Delta, NNPCL, and UTM Offshore sign agreement to develop floating LNG
Delta State Government, Nigerian National Petroleum Company Limited, and UTM Offshore Ltd have signed a shareholders agreement for the development of the first floating LNG (FLNG) in Nigeria.
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Secretary to the State Government, Dr Kingsley Emu, and Solicitor General and Permanent Secretary Ministry of Justice, Omamuzo Erebe, signed for the Delta State Government, while the Group CEO, Mele Kyari, and Group Managing Director, Julius Rone, signed for NNPC Limited and UTM Offshore, respectively.
With the agreement Delta State Government will own an 8% share of the project, NNPC Limited 20%, and UTM Offshore 72%.
Speaking at the signing ceremony at the NNPC Towers Abuja, Governor Sheriff Oborevwori of Delta State, said the UTM FLNG Project was the first of its kind to be developed by an indigenous private company in Nigeria.
Governor Oborevwori explained that the state government took 8% equity in the FLNG project because of its conviction of the strategic importance of the project to the national economy, adding that with 40% of Nigeria’s proven gas reserves in Delta State, it was a worthy investment.
According to him, the deal marked a significant milestone in the development of the project, expressing hope that construction will begin next year.
He said: “Of particular interest to Delta State Government is the dividend that this UTM FLNG will generate, thus advancing the socio-economic development of our great state. It is expected that over 300 000 t of LPG (cooking gas) will be produced and dedicated to the domestic market.
“This project will also help to mitigate the environmental hazards in the Niger Delta by reducing gas flaring. Of course, our women folk will also benefit from the fuel switch from kerosene and firewood to cleaner energy, thus improving their health and general well-being.
“Another benefit we envisage with this project is that it will create job opportunities for our youths, which is one of the four pillars of our MORE agenda.”
Kyari added: “We are happy to collaborate with the Delta State Government in this venture. The State Government is here in two capacities, one as a supporter of grow-ing gas utilisation in the country and also now as an investor in this necessary industry but potentially a valuable industry for all of us.”
Also speaking, the Minister of State Petroleum Resources (Gas), Ekprikpe Ekpo noted that it was time for the country to begin the monetisation of its huge gas reserves for the development of the economy.
Rone said the signing ceremony marks another significant milestone in actualising Nigeria’s first indigenous FLNG.
Rone said he expects the final investment decision (FID) on the project to be taken before the end of 2Q24. He commended the stakeholders for their support, especially the Delta State Government for investing in the project.
“I want to thank the Delta State Government for taking an equity on this laudable project which will create other sources of revenue for the state to develop their infrastructure that is highly needed and create employment for the teeming youths of Delta State,” Rone concluded.
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US: Gladstone LNG terminal resumes normal operations
The single berth at the east coast of Australia Gladstone LNG terminal is back to normal operations after an LNG carrier suffered problems, while Belgium’s Fluxys LNG terminal has announced the dates of forthcoming slot auctions
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Gladstone LNG terminal back to normal after LNG carrier blockage
Operations are back to normal at the Gladstone LNG terminal on the east coast of Australia a month on from the week-long blockage in November 2023, caused by 2017-built, 174,100-m3 LNG carrier Cesi Qingdao.
The vessel failed a Port State Control inspection for incorrectly stowing explosives, along with other faults, leading to a week-long stay on the berth, blocking traffic.
It was reported the vessel had lost power on the berth and was unable to move, blocking shipments from the ConocoPhillips Australia-operated LNG terminal, which can only handle one vessel at a time.
VesselsValue tracking data shows the vessel is now sailing towards China.
Fluxys LNG terminal auctions
Fluxys LNG is offering standard sized slots to unload, store and regasify an LNG cargo in the Zeebrugge LNG Terminal, starting 25 and 30 March 2024.
For these cargoes, Fluxys LNG commercialises the firm rights to unload, store and regasify up to 140 000 m³ of LNG over 10 days.
The auctions will take place 17 January 2024.
Eni introduces gas to Tango FLNG offshore Congo
Italian energy major Eni said it has begun to introduce gas into its floating LNG facility a year after taking a final investment decision on the facility.
“This is a key milestone for the Congo LNG project, which encompasses the adoption of new technologies and a strong synergy with existing producing assets. Following completion of the commissioning phase, Tango FLNG will produce its first LNG cargo by the first quarter of 2024, placing the Republic of Congo on the list of LNG-producing countries,” the company said.
Australia-based Prelude FLNG ships first cargo since August
Prelude FLNG, which has seen a significant number of stoppages due to mechanical and workforce issues, shut down for routine maintenance in August 2023. Shell reportedly confirmed that LNG cargoes have again begun to leave the facility.
One year of operations at Hooksiel LNG terminal
Germany’s first LNG terminal at the Hooksiel outer harbour, near Wilhelmshaven, celebrated its first anniversary 17 December 2023.
Since commissioning on 21 December 2022, the terminal has been running almost without interruption with 42 LNG carriers so far delivering around 7M m³ of LNG via the FSRU Höegh Esperanza – equivalent to 6% of Germany’s requirement.
Sagunto LNG terminal offers bunkering services
The LNGHIVE2: Infrastructure and Logistics Solutions project, co-ordinated by Enagás and promoted by Saggas and the Valenciaport Foundation, has adapted the Sagunto regasification terminal to offer LNG bunkering services to load small-scale vessels with a capacity of less than 6,500 m³.
Fos Cavaou LNG terminal
Elengy has inaugurated two new LNG road tanker loading bays at its Fos Cavaou LNG terminal, doubling the terminal’s loading capacity to 22,000 slots per year at a cost of €10M (US$11M).
QatarEnergy and ExxonMobil make progress on Golden Pass LNG
The pair of energy majors, holding 70% and 30% in the LNG export project, respectively, released a project update on progress at Golden Pass in a filing with the US Federal Energy Regulator Commission (FERC). The FERC said in November that the first LNG train is expected to be completed in H2 2024, with the pipeline expansion project expected to be in service prior to the first LNG train’s completion. First LNG is expected in H1 2025, according to ExxonMobil.
Qatar LNG delivers the 1,000th LNG shipment to South Hook LNG terminal
QatarEnergy LNG has delivered the 1,000th LNG shipment to the South Hook LNG Terminal at Milford Haven in the United Kingdom.
The landmark delivery was made by the Q-Max LNG carrier Mozah, which has another landmark achievement to its name: the 10,000th LNG cargo from Ras Laffan Port in 2006.
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Germany: Operations Start at new LNG Jetty in Germany’s Stade Port
Germany’s Niedersachsen Ports has begun operating a newly constructed jetty built specifically to handle the offloading of LNG from floating storage and regasification units (FSRU).
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The Port of Stade is the second port in Lower Saxony to feature a dedicated LNG jetty that will be put into operation by Niedersachsen Ports following the completion of similar infrastructure in Wilhelmshaven.
The new jetty at Stade covers four hectares and has a quay length of 1.6 kilometres and a maximum berthing draught of 16.4 metres. Niedersachsen Ports said that although the facility will initially handle LNG, it may also accommodate renewable gases such as green hydrogen and ammonia in future.
Construction of the Stade LNG jetty was completed in eleven months at a cost of approximately €300 million (US$327 million).
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Germany Builds up LNG Import Terminals
German utility RWE on Jan. 1 handed over floating liquefied natural gas (LNG) infrastructure at Brunsbuettel on the North Sea to state-owned Deutsche Energy Terminal (DET) as agreed when first imports arrived 10 months ago, it said.
DET is now the sole operational manager and markets the capacity of the Brunsbuettel Elbehafen LNG project.
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Germany’s quest to increase LNG capacity for regasification on its shores has intensified as it seeks to end reliance on Russian pipeline gas, on which Europe depended heavily prior to Moscow’s invasion of Ukraine last year.
Pending the provision of fixed terminals, Germany is using floating storage and regasification terminals (FSRUs) to help to replace piped Russian gas supplies.
Three FSRUs are working at the Wilhelmshaven, Brunsbuettel and Lubmin ports after Germany arranged their charter and onshore connections.
Wilhelmshaven, Stade and Mukran, a port on the Baltic Sea island of Ruegen due to be connected with Lubmin on the mainland, are due to add more FSRUs in the winter of 2023/24.
Industry and the government are also building up terminal capacity in anticipation of increased use of hydrogen at the sites, which when produced using renewable energy can help the transition to a lower carbon economy.
State-owned DET held auctions for regas capacities in 2024 at Brunsbuettel and Wilhelmshaven 1 in November and Stade and Wilhelmshaven 2 rounds in December.
Mukran
Private company Deutsche ReGas reported in August that suppliers had booked 4 billion cubic metres (bcm) per annum of capacity for 10 years at Mukran, where the company wants to pull together two FSRUs for deliveries to the mainland.
It has chartered a second FSRU, the Transgas Power, with regasification capacity of 7.5 bcm, to complement the Neptune currently active at Lubmin.
LNG from Mukran is targeted to flow to onshore grids via gas grid company Gascade’s new pipeline from the first quarter of 2024, which obtained approval for completion from mining authorities in November.
The project has triggered local opposition. Two legal challenges by environmental groups DUH and Nabu were thrown out by the federal administrative court in September.
Wilhelmshaven
Utility Uniper UN01.DE launched Germany’s first FSRU operations, Wilhelmshaven 1, in December 2022 at the deep-water port on the North Sea.
LNG/TKUK
Tree Energy Solutions (TES) plans to operate a second FSRU, Wilhelmshaven 2, in the years between 2024 up to 2027.
Further ahead, Uniper plans to add a land-based ammonia reception terminal and cracker in the second half of this decade. Ammonia is at times used as a carrier for hydrogen, whose low density otherwise makes transportation over long distances complicated.
TES also has plans to eventually convert its operations to clean gases.
Lubmin
The FSRU Neptune, chartered by Deutsche ReGas, began receiving LNG at Lubmin on the Baltic Sea early in 2023.
The gas is first delivered to another storage vessel, the Seapeak Hispania, and shuttled to Lubmin in a set-up taking account of shallow water.
ReGas holds long-term supply deals with France’s TotalEnergies and trading group MET.
The government wants the Neptune to move to Mukran on Ruegen island, allowing the Seapeak Hispania to depart, and join the second FSRU there, the Transgas Power.
Regas plans hydrogen electrolysis plants at both Lubmin and Mukran.
Brunsbuettel
The Brunsbuettel FSRU went into operation in April, initially chartered and operated by RWE’s trading arm before the handover to DET at the start of 2024.
It is the forerunner of a land-based LNG facility, which has been cleared to receive 40 million euros ($44 million) of state support, that could start operations at the end of 2026, when an adjacent ammonia terminal could also start up.
State bank KfW, Gasunie and RWE are stakeholders and Shell has committed to sizeable purchases.
The total costs of the land-based terminal are 1.3 billion euros.
Stade
The inland port on the river Elbe a year ago started work on a landing pier for an FSRU, to be ready in winter 2023/24.
Designated vessel Transgas Force, moored at Bremerhaven port to be fixed up for the purpose, is expected to arrive in February.
Project firm Hanseatic Energy Hub (HEH) also plans a land-based terminal where it has allocated regasification capacity to become operational in 2027.
The allocations include volumes for state-controlled SEFE, utility EnBW and Czech utility CEZ.
It has begun sounding out the market to determine whether the longer-term plans should be based largely on ammonia to be reconverted into clean hydrogen. It has identified a construction consortium.
HEH is backed by investment firm Partners Group, logistics group Buss, chemicals company Dow and Spanish grid operator Enagas.
https://www.marinelink.com/news/germany-builds-lng-import-terminals-510501
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South Korea: Samsung Secures $1.5B Order for FLNG Barge
South Korean shipbuilder Samsung Heavy Industries has secured an order for a $1.5 billion floating LNG liquefaction plant (FLNG) for an unnamed buyer in North America, according to Yonhap. The sum is equal to nearly one-fifth of all orders SHI won last year.
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Samsung will be working with Black & Veatch to design, build and deliver the new unit by 2028. The name of the customer was not described, but the timing of the award, the name of the engineering partner and the completion timetable all align with Cedar LNG, a barge-based LNG project on tribal shorefront in British Columbia.
Cedar LNG is a partnership between Pembina Pipeline and B.C.’s Haisla Nation, the first ever tribal owner of an LNG plant in Canada. With support from the center-left provincial government, the partners will install a small LNG liquefaction barge moored to Haisla land in Kitimat, B.C. The plant will generate about 100 jobs during operation and ship about three million tonnes per year of natural gas, sourced from the prolific Montney siltstone formation on the Albertan border. ARC Resources, a tight-gas producer in the Montney region, has signed an MOU to use half of Cedar LNG’s liquefaction capacity.
On site, the plant will have a comparatively favorable environmental footprint. According to its sponsors, the barge’s compressors will be powered by B.C.’s hydropower-based electric grid, and the project should rank among the world’s least emissions-intensive LNG liquefaction terminals. Its shipped product will be conventional LNG, with associated emissions from end-use combustion.
The barge will be about one nautical mile away from the pier for Shell’s LNG Canada plant, which is currently under construction. At full buildout, LNG Canada will have about 10 times the capacity of Cedar LNG. Shell recently announced that LNG Canada’s compressors will be powered by natural gas because of insufficient electrical transmission capacity for the larger shore-based plant.
https://maritime-executive.com/article/samsung-secures-1-5b-order-for-canadian-flng-barge
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US: Sempra’s Cameron LNG plant ships 700th cargo
US LNG exporter Sempra has shipped the 700th cargo of liquefied natural gas from its Cameron LNG export plant in Louisiana since 2019. Cameron LNG, the LNG terminal operator controlled by Sempra’s unit Sempra Infrastructure, announced the completion of loading of its 700th LNG cargo in a social media post last week. The cargo was exported onboard the 2018-built 174,000-cbm LNG carrier, Marvel Falcon.
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“The Marvel Falcon represents the 189th export cargo loaded this year as we continue to set records on daily LNG production throughout December,” Cameron LNG said.
According to its AIS data provided by VesselsValue, the LNG carrier, owned by NYK Line and chartered by Mitsui, departed Cameron LNG on December 10 and delivered the shipment on December 27 to Germany’s FSRU-based LNG import terminal in Brunsbüttel.
The Cameron LNG plant has three liquefaction trains with a total capacity of about 12 million tonnes per year of LNG or about 1.7 billion cubic feet per day (Bcfd).
Cameron LNG’s first train started commercial operations in August 2019, followed by the launch of operations at the second train in March 2020, and the third train in August 2020.
The plant shipped its 100th cargo of LNG in August 2020.
Besides Sempra Infrastructure, other partners in Cameron LNG include affiliates of TotalEnergies, Mitsui & Co, and Japan LNG Investment, a company held by Mitsubishi Corp and NYK.
In addition to these three trains, Sempra and its partners are working to expand the facility with the fourth train with a capacity of about 6.75 mtpa.
The partners selected Bechtel to build the Cameron Phase 2.
Justin Bird, CEO of Sempra infrastructure, said in August 2023 that the partners plan to take FID on the expansion project in 2024.
https://lngprime.com/americas/sempras-cameron-lng-plant-ships-700th-cargo/101197/
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Qatar : QatarEnergy, ExxonMobil moving forward with Golden Pass LNG work
Energy giants QatarEnergy and ExxonMobil released the latest construction update for their Golden Pass LNG export terminal on the US Gulf Coast near Sabine Pass, Texas. State-owned QatarEnergy owns a 70 percent stake in the Golden Pass project with a capacity of more than 18 mtpa and will offtake 70 percent of the capacity, while US energy firm ExxonMobil has a 30 percent share.
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A joint venture of Chiyoda, McDermott, and Zachry is building the tree Golden Pass trains worth about $10 billion next to the existing LNG import terminal.
Golden Pass LNG Terminal and Golden Pass Pipeline said in the newest construction report filed with the US FERC that Golden Pass is continuing to carry out Phase I and Phase II activities.
Golden Pass and its contractors progressed installation of piping and steel in process and utilities areas and flare wall modifications, continued piping and vessels insulation activities, while concrete foundation pours continued in Train 2 and Train 3.
In addition, Golden Pass progressed setting various vessels on respective foundations and progressed brownfield tie-ins in Trains 2 and 3, and progressed brownfield tie-ins and LNG tank tops modifications scope.
Golden Pass also progressed cable tray installations and cable pulling activities and continued pipe pneumatic / hydrostatic testing program.
As per the pipeline expansion project, Golden Pass continued civil activities and concrete foundation pours at milepost MP33 and MP69 compressor stations and also continued pipe fabrication and installation at these stations.
It also continued construction activities of the Sabine Spur, Natural Gas Pipeline (NGPL)
Interconnect improvements, and associated facilities.
H1 2025
Regarding the start of operations, the FERC said in an inspection report in November that the anticipated timing for the first Golden Pass train is the second half of 2024, with the second and the third train following after.
The anticipated in-service timing for the pipeline expansion project is expected sometime prior to the second half of 2024, it said.
ExxonMobil’s senior VP and CFO, Kathryn Mikellss, recently said that “train 1 mechanical completion is expected at the end of 2024 with first LNG in first half of 2025.”
The US currently exports LNG via Cheniere’s Sabine Pass and Corpus Christi plants, Sempra’s Cameron LNG terminal, Venture Global’s Calcasieu Pass facility, the Freeport LNG terminal, Berkshire Hathaway’s Cove Point terminal, and Kinder Morgan’s Elba Island facility.
Besides the Golden Pass LNG export plant, Venture Global expects to start commissioning its Plaquemines LNG facility this year.
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US was top LNG exporter in 2023 as deliveries hit record levels
HOUSTON, Jan 2 (Reuters) – U.S. liquefied natural gas exports hit monthly and annual record highs in December, tanker tracking data showed, with analysts saying it positioned the United States to leapfrog Qatar and Australia to become the largest exporter of LNG in 2023.
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The U.S. was the stand out in global LNG supply growth in 2023, said Alex Munton, director of global gas and LNG research at consulting firm Rapidan Energy Group of the rise to 8.6 million metric tons leaving U.S. terminals in December
Qatar was the largest LNG exporter in 2022 and Australia the second-largest that year, U.S. government data showed.
“U.S. record production was driven by two factors: the return of Freeport LNG to full service, which added 6 MT and the full-year output of Venture Global LNG’s Calcasieu Pass facility that added 3 MT more than in 2022,” Munton said.
Full year exports from the U.S. rose 14.7% to 88.9 million metric tons (MT) driven largely by the return to full production of the Freeport LNG plant that had suffered a fire in 2022, and as others increased processing efficiency, LSEG data showed.
Shipments compare to 77.5 million metric tons in 2022, the data from the financial information provider showed.
Europe remained the main destination for U.S. LNG exports in December, with 5.43 MT, or just over 61%. In November, 68% of U.S. LNG exports were to Europe, LSEG data showed.
The month-over-month drop reflected warmer than normal temperatures in Europe and elevated storage levels, analysts at consultants Rystad Energy said. European gas storage was about 97% full at the beginning of December, it reported.
Asia was the second largest export market for U.S. LNG in December, taking 2.29 MT, or 26.6%, of exports, up from 18.5% in November. U.S. exports to Latin America were half a million metric tons, or just under 6% of total exports, LSEG ship tracking data showed.
Natural gas flows to the seven big U.S. LNG export plants have climbed an average 14.9 billion cubic feet per day (bcfd) so far in January, up from a monthly record of 14.7 bcfd in December. That topped the prior all-time monthly high of 4.3 bcfd in November, LSEG data showed.
U.S. gas was trading Tuesday morning at $2.55 per million British thermal units (mmBtu) at the Henry Hub benchmark in Louisiana, $9.81 per mmBtu at the Dutch Title Transfer Facility (TTF) benchmark in Europe and $11.52 per mmBtu at the Japan Korea Marker (JKM) in Asia.
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Congo : Milestone hit as Eni introduces gas into Congo’s floating LNG facility
European energy firm Eni has introduced gas into the Tango floating liquefied natural gas (FLNG) facility moored in Congolese waters. The company achieved the feat just twelve months after the final investment decision, marking a key milestone for the Congo LNG project.
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Eni’s $5bn Congo LNGproject will see the installation of two FLNG plants and is expected to reach an overall LNG production capacity of three million tons per year (approximately 4.5 billion cubic metres/year) from 2025.
Equipped with a liquefaction capacity of about one billion bcm per year, Tango will produce its first LNG cargo by the first quarter of 2024, placing the Republic of Congo on the list of LNG-producing countries.
Moored alongside the Excalubur floating storage unit (FSU), the Tango facility uses a configuration called ‘split mooring – a first for a floating LNG terminal.
Congo LNG’s second FLNG facility (3.5 bcm per year) is currently under construction and will begin production in 2025, according to Eni.
“Eni has been operating in Congo for 55 years and is the only company active in the development of the country’s gas resources,” stated the company.
“Eni currently supplies gas to the Centrale Électrique du Congo (CEC), which provides 70% of the country’s power generation capacity.”
In addition to working to promote the nation’s energy transition through several initiatives, the company is also working on the production of agricultural raw materials to be used as biofuel feedstocks.
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Greece’s first FSRU to receive commissioning LNG cargo on January 20
Greece’s Gastrade expects to receive on January 20 the commissioning cargo at its FSRU-based LNG import terminal in Alexandroupolis. The firm launched a tender on October 31 for the supply of the commissioning cargo and relevant services. It extended the deadline for two times and the second deadline extension ended on December 15.
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“The commissioning cargo is anticipated to arrive on the 20th of January in which then commissioning will begin and will last for 6-7 weeks,” Gastrade told LNG Prime in emailed comments on Wednesday.
Gastrade did not say who won the tender for the commissioning cargo.
“If no major issues arise during commissioning, the project will reach commercial operations in the first week of March, as planned,” the firm said.
Gastrade’s shareholders include founder Copelouzou, DESFA, DEPA, Bulgartransgaz, and GasLog.
Shareholder and Greek LNG shipping firm GasLog told Singapore’s Keppel Offshore & Marine, now Seatrium, in February 2022 to proceed with the conversion of the 2010-built, GasLog Chelsea, to an FSRU.
After that, the vessel entered the yard in February last year and the partners renamed it to Alexandroupolis.
Seatrium’s yard in Singapore completed the conversion work on the 153,600-cbm Alexandroupolis in November last year.
Hook-up completed
Greece’s first FSRU arrived in Alexandroupolis from Singapore on December 17.
“The FSRU, upon arriving to site on Sunday 17th of December, has been safely hooked up to its mooring system at its permanent mooring position,” Gastrade said.
“Mooring hook-up was completed on the 23rd of December 2023,” the firm said.
The first FSRU is located in the sea of Thrace at a distance of 17.6 km SW from the port of Alexandroupolis and 10 km from the nearest coast of Makri. Also, it will be connected to a high-pressure subsea and onshore gas transmission pipeline.
Once operational, the pipeline will deliver natural gas to the Greek transmission system and onwards to the final consumers in Greece, Bulgaria, Romania, North Macedonia, Serbia and further to Moldova and Ukraine to the East and Hungary and Slovakia to the West, Gastrade said.
The Alexandroupolis LNG terminal will have a capacity of 5.5 Bcm.
With this project, Greece will get its first FSRU and the second LNG import facility, adding to DESFA’s import terminal located on the island of Revithoussa.
In addition to this unit, Gastrade is also planning to install a second FSRU offshore Alexandroupolis.
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LNG as a Marine Fuel/Shipping
Hong Kong: Seaspan LNG Bunkering Vessel Launched
Seaspan Energy announced the launch of Seaspan Garibaldi, the first of three 7,600m3 liquefied natural gas (LNG) bunkering vessels being built by CIMC Sinopacific Offshore & Engineering (CIMC SOE) in China.
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The newbuild is named after Mount Garibaldi, or “Nch’ḵay̓” as the Squamish Nation has known it for thousands of years. This series of vessels will be named after iconic West Coast mountains and the first two vessels will be delivered in 2024 with the third vessel arriving in 2025.
The Seaspan Garibaldi will be based in the Panama region, and the second vessel is targeted to support the West Coast market as it develops.
“There is significant global interest in developing and investing in LNG bunkering solutions and Seaspan Energy is uniquely positioned to provide leadership in this growing market because of our advanced LNG capabilities and expertise,” said Ian McIver, President of Seaspan Energy. “Developing an LNG bunkering business is a natural progression for Seaspan, as the company already provides traditional fueling services and is a highly experienced LNG vessel operator with a fleet of hybrid ferries that operate primarily on LNG.”
The Seaspan Garibaldi is 112.8 meters in length, 18.6 meters in width, 5 meters in draft, with a design speed of 13 knots.
For the design of the LNG Bunker Vessels, Seaspan worked closely with the Canadian-based team at VARD Marine Inc. to incorporate emerging technologies resulting in a decrease in emissions and underwater noise. The design is focused on safe, efficient, and economical refueling of multiple ship types with an ability to transfer to and from a wide range of terminals. The design will allow the vessel to engage in ship-to-ship LNG transfer and coastal and short-sea shipping operations.
https://www.marinelink.com/news/seaspan-lng-bunkering-vessel-launched-510615
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West Africa: Golar’s FLNG expected to arrive in Senegal this week
Golar LNG’s converted FLNG, Gimi, which will serve the first phase of BP’s Greater Tortue Ahmeyim project offshore Mauritania and Senegal, is expected to arrive in Dakar this week, according to shipping data. The FLNG, which was converted from a 1975-built Moss LNG carrier with a storage capacity of 125,000 cbm, departed Seatrium’s yard in Singapore on November 19.
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Golar said at the time that it expects the voyage to take around 60 days, including refueling stops in Mauritius prior to rounding the Cape of Good Hope and in Namibia prior to its arrival.
The 293 meters long converted FLNG is sailing under its own propulsion, supported by the 88.9 meters long escort tug, ALP Defender, according to Golar.
Gimi and ALP Defender were on Monday located offshore Guinea and are expected to arrive in Dakar on January 10, their AIS data shows.
Upon arrival, Gimi will notify BP that it is ready to be moored and connected to the GTA hub, which is expected to trigger the start of contractual cash flows under the 20-year lease and operate agreement on the GTA field, Golar previously said.
Back in February 2019, Golar entered into the deal with BP for the charter of the FLNG.
This is the world’s second converted floating LNG producer and joins Golar’s Hilli, also converted by Seatrium and currently located offshore Cameroon’s Kribi.
Gimi will produce up to 2.7 million tonnes of LNG per year, using the Black & Veatch “Prico” liquefaction process.
Project delayed due to subsea work
Following arrival of the FLNG and the FPSO at the GTA hub, BP will start upstream commissioning and supply of gas to the FLNG.
Golar said in its third-quarter report that commissioning is expected to take about six months from the commissioning start date with commercial operations (COD) expected thereafter.
This means that the commercial launch of the project could be achieved in the second or third quarter of 2024.
Golar and the GTA partners are “working on initiatives to further optimize the commissioning period in order to achieve COD as early as possible,” it said.
BP’s interim CEO Murray Auchincloss told analysts during BP’s third-quarter earnings call that the company is “hopeful” that it will launch the first phase of its Greater Tortue Ahmeyim FLNG project in the first quarter of 2024.
The company pushed back the start of the project due to a delay in the subsea scope.
However, US firm and project partner Kosmos said in its third-quarter report that the delivery of first gas from the first phase of the project has the potential to slip into the second quarter of 2024.
In October, BP selected Swiss-based offshore contractor Allseas to complete the remaining subsea pipelay scope for the FLNG project, replacing previous contractor Houston-based McDermott.
Allseas said in December that it has started GTA offshore pipelay work using what it says is the world’s largest construction vessel, Pioneering Spirit. Allseas’ offshore construction support vessel Oceanic is providing installation support.
Pioneering Spirit will complete the pipelay scope, which covers the approximately 75 km outstanding on the two export gas lines and four CRA infield lines, with multiple structures, Allseas said.
FPSO
As per the project’s FPSO unit, it left Cosco Shipping Heavy Industry’s yard in Qidong, China in January last year.
Kosmos previously said the FPSO was expected to arrive on location in the first quarter of 2024.
Its AIS data showed on Monday that it was located offshore Dakhla and heading north, not south toward Mauritania.
Following arrival and completion of commissioning activities at the site offshore Mauritania and Senegal, the FPSO will process natural gas – removing condensate, water, and other impurities – before exporting it by pipeline to the project’s FLNG facilities, 10km offshore.
With eight processing and production modules, the FPSO will process around 500 million standard cubic feet of gas per day.
The FLNG will liquefy majority of the gas, enabling export to international markets, while some of the supplies will help meet growing demand in the two host countries, BP previously said.
https://lngprime.com/africa/golars-flng-expected-to-arrive-in-senegal-this-week/101712/
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Canada: ‘Floatel’ ship arrives in B.C. to house LNG workers, but local permit still needed
VANCOUVER – A cruise ship renovated to house more than 600 workers at a natural gas construction project north of Vancouver arrived in British Columbia waters this week after a 40-day journey from Estonia, where it had accommodated Ukrainian refugees.
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Bridgemans Services Group, the company contracted to provide the so-called “floatel” or floating hotel, for workers at the Woodfibre LNG project near Squamish, B.C., shared a photo of the MV Isabelle in Vancouver’s Burrard Inlet on Wednesday.
However, the mayor of Squamish said the district council has yet to consider the application for a temporary use permit to allow the plan to proceed.
Armand Hurford said staff are reviewing the application from Woodfibre LNG with a ”public process” and council decision to follow.
In an interview on Friday, the mayor said he isn’t sure when the application will be sent to council, but it hadn’t appeared on the schedule for the rest of this month.
Woodfibre LNG said it was planning for workers to start occupying the ship this spring.
Hurford would not say whether he would support the plan when it comes time to vote, although he said the floating accommodation is a “creative solution” as Squamish grapples with a rental vacancy rate of just 0.7 per cent.
“We knew that was the path they were going to pursue, but the last piece of that is the permitting required to do that, and you know, often the devil’s in the details.”
Hurford said figuring out accommodation for temporary workers should be an integral part of the approval process for major infrastructure projects.
Otherwise, he said municipalities are left grappling with the housing and social impacts “at a really awkward time in the cycle of a project.”
The Union of B.C. Municipalities adopted a resolution put forward by the Squamish council last fall, requesting that the provincial government require detailed workforce housing plans when considering the approval of such developments.
Christine Kennedy, president of Woodfibre LNG, said it has always been a priority to ensure the facility’s construction “has as little impact on Squamish as possible.”
The statement said floating accommodation alleviates concerns about the impact of temporary workers on local housing and community services as well as the potential for environmental harm associated with “standard” work camps.
Hurford said he doesn’t know why the temporary use application for the “floatel” was made so late in the process, but he speculated it may have stemmed from the company’s desire to maximize use of an initial three-year permit.
“We see it often with a proponent where they want to have the use of that for as long as possible.”
The timeline for potential approval depends in part on the quality of the application, the mayor said.
“Obviously, they’re confident in their application and in the solution and they’ve invested enough to get to this point.”
The statement from Bridgemans said the “luxury” accommodation vessel was set to receive “final touches” at a North Vancouver shipyard, including games tables and equipment for a fitness facility, before making its way up Howe Sound to the site of the former pulp and paper mill seven kilometres southwest of Squamish.
The ship recently housed people fleeing war in Ukraine, and a statement from Woodfibre LNG said it has since undergone an “extensive refit” to its environmental systems and its living, dining and recreation areas.
The ship has sewage and water treatment systems, industrial-sized heat pumps, and it may be connected to the BC Hydro electricity grid. Its treated sewage is to be shipped to waste management facilities in the province, the statement said.
The MV Isabelle is set to be moored at the Woodfibre project site, so those living on board can walk to work, it added.
The “floatel” includes catered dining areas, laundry rooms, a first-aid clinic and a games room, in addition to the “state-of-the-art” fitness facility, it said.
Bridgemans will have a crew on board at all times to inspect the ship and ensure fire, water and other safety systems meet Canadian regulations, it said.
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Technological Development for Cleaner and Greener Environment Hydrogen & Bio-Methane
Germany: Westfalen Group switches to Bio-LNG for climate-friendly heavy-duty transport
Germany-based technology company in the energy sector Westfalen Group (Westfalen) has announced that Bio-liquefied natural gas (LNG) will replace its fossil counterpart at its four Westfalen LNG filling stations in Münster, Herford, Herne and Cologne.
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Produced from upgraded and liquefied biogas, Bio-LNG could support Europe’s journey towards sustainable mobility.
Compared to diesel, fossil LNG can save around 20% of CO2 emissions in heavy-duty transport, whereas Bio-LNG enables savings of up to 100%, according to Andre Stracke, Head of Mobility at Westfalen.
“In addition, hardly any nitrogen oxides and fine dust are released during combustion. This makes the fuel very attractive for our customers who want to offer their freight services more sustainably.”
Customers that have already converted their fleet to LNG could also use Bio-LNG to meet demand for more sustainable logistics.
The decision to switch to Bio-LNG originates from a deal between Westphalia and revis bioenergy GmbH that was established in March 2023.
Heavy-duty vehicles (HDVs), such as trucks, city buses and long-distance buses, are responsible for more than 25% of GHG emissions from road transport in the EU and account for over 6% of total EU GHG emissions (European Commission)
Münster-based Westfalen generates biomethane from regionally produced waste and residues before it is liquefied to create Bio-LNG. Liquefaction reduces the volume of the gas by 600 times, greatly increasing the energy density.
According to studies, by 2050 Bio-LNG can reduce greenhouse gas (GHG) emissions in the transport sector by 95% to 174%.
“Collaborations with strong partners like revis are essential for the transformation to low-emission mobility,” said Julian Janocha, Head of Gas Mobility at Westfalen.
“Converting the four existing locations to Bio-LNG is an important milestone for Westphalia. Wherever customers report needs to us, we also strive to further expand our Bio-LNG filling station network,” he added, before revealing that additional locations are already being planned.
Research published by the European Biogas Association revealed that EU production of Bio-LNG is set to increase tenfold by 2030 from 2020.
EU LNG heavy-duty transport is expected to reach 280,000 units in the same period and – using a 40% Bio-LNG mix with LNG – will help reduce the carbon dioxide (CO2) emissions from those trucks by 55%.
Speaking at the release of the report, Harmen Dekker, Director of the EBA, called BioLNG ‘scalable for tomorrow’, adding, “It is a sustainable and cost competitive carbon neutral fuel if we take into account all positive externalities of the Bio-LNG value chain.”
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Columbia: Equinor’s H2M Eemshaven project to reform natural gas to hydrogen with CCS
Norwegian energy major Equinor and global industrial gases and engineering company Linde have signed a project development agreement to work as partners on the H2M Eemshaven low-carbon hydrogen project in the Netherlands. Equinor’s H2M Eemshaven project aims to build a production facility in the Eemshaven industrial area, where it will reform natural gas from the Norwegian continental shelf (NCS) to hydrogen with CO2 capture and storage (CCS).
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More than 95% of the CO2 will be captured and stored safely and permanently under the seabed offshore Norway. The aim is to start production in late 2028 and the hydrogen plant will be connected to onshore hydrogen pipelines planned in both the Netherlands and Germany.
Under the project development agreement, Equinor will secure access to carbon transport and storage capacity and offer low-carbon hydrogen to the market. Linde will build, co-own, and operate the hydrogen production and carbon capture and transfer facility.
“The H2M Eemshaven project is part of our strategy to develop hydrogen production in three to five major industrial clusters in Europe by 2035. Linde’s experience with the safe development, execution and operation of hydrogen and carbon capture plants complements Equinor’s experience and competence within energy marketing and CCS,” said Grete Tveit, Senior Vice President for low-carbon solutions in Equinor.
“Together we can produce low carbon hydrogen to ensure reliable and clean energy to Europe. We look forward to developing this important project together with Linde.”
Stefano Innocenzi, President Region Europe West, Linde, added: “The transition to a low-carbon economy is steadily gaining momentum. We look forward to working with Equinor and contributing Linde’s technology and expertise to develop this flagship project.”
H2M Eemshaven is expected to contribute to delivering on Equinor’s climate ambition and hydrogen strategy which positions Equinor in three to five major industrial clusters underpinning an ambition of 10% of European hydrogen market share by 2035.
With a production capacity of 1 GW (235,000 tons), the project will meet 2.3% of Europe’s existing grey hydrogen demand and 0.24% of the European clean hydrogen market forecast for 2050.
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South Korea: Woodside links with South Korean gas giant on ‘lower-carbon’ hydrogen deal
Oil and gas giant Woodside Energy has signed a deal with South Korean utilities major SK E&S to explore the potential development of a “lower-carbon” hydrogen value chain between Australia and South Korea.
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Woodside Energy has signed a non-binding memorandum of understanding with SK E&S, South Korea’s largest private renewable energy operator, to enable studies relating to investments and potential offtake deals in lower-carbon hydrogen and ammonia projects across Australia and South Korea.
Under the agreement, Woodside and SK E&S plan to jointly explore opportunities relating to long-term offtake arrangements and equity participation in ammonia and hydrogen production projects, and project engineering supply opportunities.
Woodside Executive Vice President New Energy Shaun Gregory said the agreement reflects the increasing demand for large-scale clean energy solutions from the company’s industry partners in the Asia Pacific region.
“This collaboration will help inform our development of the new energy products and services which could support our customers’ decarbonisation, unlock new market opportunities and support the broader Asia Pacific region in their climate goals and net zero aspirations,” he said.
Woodside has previously announced plans to allocate more than $7 billion (USD 5 billion) to clean energy ventures by 2030 as it works to enhance its resilience to the energy transition.
The Perth-based oil and gas producer is already progressing a series of new energy ventures, including the recently approved 500 MW solar farm being developed near Karratha in Western Australia’s northwest.
It is also hydrogen projects in development near Perth, in Tasmania, and in New Zealand, and is also examining a solar thermal project in the United States.
SK E&S, which is active in the development of gas fields, including in northern Australia, and in the distribution of gas to customers across eight regions in South Korea, is planning to become a major global hydrogen provider by utilising its LNG business infrastructure and value chain integration capability.
The company is also planning to become a major player in the clean energy sector, targeting 7 GW of renewable generation capacity by 2025. At present, the company has about 2.5 GW of renewables in operation and development.
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