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Post by Blitz on Nov 21, 2022 18:18:25 GMT -5
Ministry of Mines and Energy classifies the project for the new FPSO in the Atlanta field as a priority brazilenergyinsight.com/2022/11/21/ministry-of-mines-and-energy-classifies-the-project-for-the-new-fpso-in-the-atlanta-field-as-a-priority/(PN) The Ministry of Mines and Energy gave the seal of “priority” to the project to implement the new FPSO in Enauta’s Atlanta field, located in the Santos Basin. As a reminder, the new platform will be used in the field’s definitive production system. The FPSO OSX-2 (renamed FPSO Atlanta), which will be used in the definitive production system, will have the capacity to produce 50,000 barrels of oil and process 140,000 barrels of water per day. When classified as a priority, as defined by Decree No. 8,874, of 2016, a given project can issue the so-called incentivized debentures – created by Law No. 12,431/2011 with the objective of enabling the construction of a primary market for long-term financing as complementary source. Once the projects are approved as priority, the company responsible for the project can take steps to issue the debentures incentivized to finance the venture. The approval of the Atlanta Definitive System as a priority project was published today in the Official Journal of the Union. The FPSO should start operating by June 2024. The Atlanta development project provides for the drilling of ten producing wells distributed in different stages.
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Post by Blitz on Nov 24, 2022 9:56:46 GMT -5
FPSO Anna Nery heads towards the Marlim field in the Campos Basin 11/24/22 brazilenergyinsight.com/2022/11/24/fpso-anna-nery-heads-towards-the-marlim-field-in-the-campos-basin/#more-50445(TN) The FPSO Anna Nery left the BrasFELS shipyard, in the city of Angra dos Reis (RJ), and headed for its final destination, the Marlim field, in the Campos Basin. The vessel has the capacity to produce up to 70,000 barrels of oil per day and process up to 4 million m³ of gas per day. The plant should start operating in the first quarter of next year. The ship was named in honor of a great character in Brazilian history – Anna Nery, a pioneer of nursing in Brazil, was responsible for providing volunteer services in the Paraguayan War (1864-1870) in military hospitals. FPSO Anna Nery is part of the Campos Basin Renewal Plan, whose objective is to renew mature assets operated by the company in the region. Petrobras is investing US$ 16 billion in this program, which is part of its Strategic Plan for the period from 2022 to 2026. “An international hub of offshore technology and cradle of deepwater production in Brazil, the Campos Basin was a pioneer in innovation and will continue to being both for decommissioning projects and for the revitalization of mature concessions”, the state company said in a statement. The vessel will be anchored in a water depth of 927 meters and interconnected to 32 wells, with peak production scheduled for 2025. The Marlim Revitalization Project plans to replace the nine platforms currently operating in the Marlim and Voador fields (P-18 , P-19, P-20, P-26, P-32, P-33, P-35, P-37 and P-47) by the new FPSOs Anna Nery and Anita Garibaldi – the latter being scheduled to start production as well in 2023.
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Post by Blitz on Nov 25, 2022 10:27:23 GMT -5
This was published in the Macau News. It must be the Chinese connection... Eni eyeing second offshore LNG platform with Mozambique government Italian oil company bullish on prospects, citing its reserves, technological know-how, strong and committed team, track record and government support. 25 NOVEMBER 2022 - BY STAFF REPORTER macaonews.org/portuguese-speaking-countries/eni-eyeing-second-offshore-lng-platform-with-mozambique-government/Italian oil company Eni is hoping to launch a second liquefied natural gas production (LNG) platform in Mozambique. “There are opportunities to increase supply in the short term, including the possibility of replicating the success of the Coral Sul project with a new Floating Liquified Natural Gas development similar to the one that began exporting gas from the Rovuma basin earlier this month,” said Eni’s Director of Natural Resources Operations, Guido Brusco. Brusco was speaking in Pemba, on the sidelines of the official inauguration of the Coral Sul platform by the Mozambican president, Filipe Nyusi. The platform has been stationed 40 kilometres off the Mozambican coast since the beginning of the year and began exporting LNG earlier this month. Although the idea of a second platform has already been discussed for about a year, Brusco’s announcement highlights the importance and opportunity of the investment. “What is clear is that we need to act quickly. Everything is in place to achieve this goal: we have reserves, technology, a strong and committed team, a track record of delivery achieved with the Coral Sul platform and government support,” Brusco said. “We will continue to work closely with partners and the government to assess all possible options for further developments.” The Coral Sul platform operated by Italian oil company Eni on behalf of the Area 4 consortium in Mozambique will produce 3.4 million tonnes of liquefied natural gas (LNG) per year for BP, which has bought the production for the next 20 years. The first export cargo ship was loaded with Mozambican LNG on 13 November. There are two other larger projects approved for the Rovuma basin, led by TotalEnergies (Area 1) and Exxon/Eni (Area 4), each of which could produce four to five times as much LNG. The possible onshore liquefaction plants on the Afungi peninsula are waiting for decisions by the oil companies for construction to go ahead, given the insecurity in the region. Area 4 is operated by Mozambique Rovuma Venture (MRV), a joint venture co-owned by ExxonMobil, Eni and CNPC (China), which holds a 70 per cent stake in the concession contract. Galp, Kogas (South Korea) and Empresa Nacional de Hidrocarbonetos (National Hydrocarbons Company of Mozambique) each have a 10 per cent stake.
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Post by Blitz on Nov 29, 2022 9:17:50 GMT -5
With construction done, topsides integration next on the list for Woodside FPSO PROJECT & TENDERS November 29, 2022, by Melisa Cavcic www.offshore-energy.biz/with-construction-done-topsides-integration-next-on-the-list-for-woodside-fpso/Following the completion of the construction phase for a floating, production, storage, and offloading (FPSO) vessel, Australia’s energy giant Woodside has tucked “another important milestone” under its belt for the first phase of Senegal’s first offshore oil development. Woodside Energy revealed on Tuesday that the construction phase for this FPSO, which is destined to be deployed at the Sangomar field off Senegal, has been completed. The first phase of this project will consist of a stand-alone FPSO, 23 subsea wells, and supporting subsea infrastructure designed to allow the tie-in of subsequent phases. The Australian company has been working on the Sangomar field development Phase 1, targeting approximately 230 million barrels of crude oil, since the project was sanctioned in January 2020. As a result, Woodside awarded the contract for the supply of the FPSO, named after Senegal’s first president, Leopold Sédar Senghor, for this project to MODEC that same year. Furthermore, China’s Cosco started converting a very large crude carrier (VLCC) into an FPSO for the Sangomar project last year. Woodside now underlined that COSCO Shipping Heavy Industry (Dalian) completed the hull and marine works, external turret and topsides module installation and conversion work on the vessel.
Moreover, the topside modules were fabricated by both COSCO and BOMESC Offshore Engineering Company in Tianjin, and the external turret mooring system was done by Penglai Jutal Offshore Engineering Heavy Industries (PJOE). Acknowledging the work done by MODEC, COSCO, BOMESC and PJOE in completing the fabrication and conversion works, Meg O’Neill, Woodside Energy CEO, remarked: “The Chinese yards achieved excellent safety performance throughout this phase of construction, logging more than 16 million hours of complex construction work without a lost-time injury event. “The construction teams also successfully navigated the challenges posed by pandemic-related travel and logistical restrictions throughout 2021 and 2022, ensuring the FPSO remained on schedule for start-up at the Sangomar field in late 2023.” Woodside confirmed that the FPSO is now being relocated to Keppel Offshore & Marine’s Tuas Shipyard in Singapore. As a reminder, Keppel was hired by MODEC a few months ago to complete topsides integration and support pre-commissioning and commissioning activities for this FPSO. Once completed and delivered to Woodside, the FPSO, which will have the capacity to process 100,000 barrels of oil per day, will be moored in waters approximately 780 metres deep and will be located approximately 100 km south of Dakar, Senegal. The Australian giant underscored that the Sangomar field development Phase 1 is currently around 70 per cent complete and will be Senegal’s first offshore oil project. Woodside is the operator with an 82 per cent participating interest in the project, while its parent, Petrosen, holds the remaining 18 per cent.
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Post by Blitz on Nov 29, 2022 9:37:13 GMT -5
I'm guessing there will be more ship conversions required to get 21 FPSOs by 2029? And now this... Brazil: Development of the Production Sharing contracts may require 21 FPSOs by 2029 brazilenergyinsight.com/2022/11/29/brazil-development-of-the-production-sharing-contracts-may-require-21-fpsos-by-2029/(epbr) The development of the 18 production sharing contracts currently contracted may require the contracting of 21 production platforms (FPSOs) of up to 225 thousand barrels/per day of capacity by 2029, estimates Pré-Sal Petróleo (PPSA). — Investments in production development are estimated at US$ 72.4 billion between 2023 and 2032, which include everything from the construction of 319 production and injection wells to new units. — The projections were updated this month and will be detailed at the 5th PPSA Technical Forum, which will be held this Tuesday (29/11). The total production of the sharing contracts should reach 2.949 million barrels of oil per day in 2030. The Union’s oil share could reach 920 thousand barrels per day in 2031. — In ten years, accumulated production could reach 7.7 billion barrels, with 1.9 billion barrels destined for the Union by 2032. With current projections for the price of oil, sales revenue could reach US$ 157 billion in the period, in addition to US$ 187 billion in royalties and federal taxes.
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Post by Blitz on Nov 30, 2022 13:54:27 GMT -5
Check out the FPSOs heading to Brazil and Guyana...
Guyana is most significant new entrant to global oil industry – WoodMac
By OilNOW - November 30, 2022
oilnow.gy/featured/guyana-is-most-significant-new-entrant-to-global-oil-industry-woodmac/
Global research group, Wood Mackenzie, said last week that Guyana is the most significant new entrant to the global oil industry.
It noted that the country will be producing one million barrels of oil equivalent per day (boe/d) within the next five years. Against WoodMac’s projection that deepwater production will grow 6 million boe/d in this decade, Guyana’s contribution to this mix is sizeable.
ExxonMobil, operator of the largest block in Guyana, plans to place six floating production, storage, and offloading (FPSO) vessels offshore by 2027. Together, these vessels will be capable of producing 1.2 million barrels of oil per day. But stakeholders and analysts, such as Hess Corporation and Rystad Energy, see a lot of room for upside in this regard.
The partners have said that they see potential for 10 FPSOs altogether producing in the Stabroek Block closer to the end of the decade.
Brazil, WoodMac said, remains the leading deepwater producer, accounting for around 30% of current global capacity and will continue to grow. Like Guyana, Brazil’s growth plans in the next few years, involve placement of several more FPSOs. State producer, Petrobras, has a strategic plan 2022-2026 that, already in play, that lists 15 FPSO’s altogether. This will hike capacity by more than 2 million barrels per day. Rystad estimates that by the end of the decade, Guyana will be second only to Brazil, on the deepwater stage.
Deepwater barrels are seen as advantaged barrels because they tend to be hyper productive, recovering huge volumes of oil and gas from each well, WoodMac said. This translates to high economic returns and low Scope 1 and 2 emissions intensities relative to most oil and gas resource themes. But with Brazil’s scale, WoodMac said it is the highest absolute emitter and its performance is contingent on Petrobras’ decarbonisation aspirations.
While Guyana and Brazil will produce the lion’s share of deepwater oil by the end of the decade, WoodMac said 14 other countries will contribute to the deepwater supply mix in the coming years.
“Deepwater is the fastest growing upstream oil and gas resource theme,” the firm said. “From just 300,000 barrels of oil equivalent per day (boe/d) in 1990, production is expected to hit 10.4 million boe/d in 2022. By the end of the decade, that figure should pass 17 million boe/d.”
This, according to WoodMac, would represent an increase of more than 60% from 2022 to 2030, and an increase from 6% to 8% of all upstream production. It said ultra-deepwater production, from depths of 1,500 metres and above, is growing fastest. By 2024, the ultra-deep is expected to account for more than half of all deepwater production. WoodMac defines deepwater production as those occurring at depths of 400 metres or more.
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Post by Blitz on Dec 3, 2022 9:32:09 GMT -5
Petrobras to relaunch tender to contract P-81 FPSO (Sergipe-Alagoas), this time in a charter mode brazilenergyinsight.com/2022/12/03/petrobras-to-relaunch-tender-to-contract-p-81-fpso-sergipe-alagoas-this-time-in-a-charter-mode/The director of production development at Petrobras, João Henrique Rittershaussen, declared that the tender for contracting the P-81, foreseen for the Sergipe Aguas Profundas project (SEAP 1), will be launched in the coming months. This time, the bidding will gain a new format compared to the previous process and will be carried out under the charter modality. As a reminder, the first attempt to hire the P-81 ended unsuccessfully. The competition was carried out in the so-called BOT (build-operate-transfer) model. In this modality, the winning bidder builds and operates the ship for an initial period and subsequently transfers the plant to the oil company. Ocyan made the only proposal in the process, but negotiations with Petrobras did not advance. The future FPSO P-81 is being designed to produce 120,000 barrels of oil/condensate per day and flow 8 million m³ of natural gas per day. The Sergipe-Alagoas Basin is the great new frontier for Petrobras oil and gas production development. Petrobras’ new business plan foresees a total of US$ 64 billion in investments for the exploration and production segment. The value is 12% higher compared to the previous plan, due to the addition of new projects, such as tenders for FPSOs Sépia 2 and Atapu 2; opportunities in complementary projects; and macroeconomic and market assumptions and project adjustments.Rittershaussen also reinforced the forecast that the FPSO P-71, which will produce in the Itapu field, should start operating later this month, with a capacity of 150,000 barrels per day. The vessel is already in the field, with interconnected lines and in the process of commissioning. In the period between 2023 and 2027, Petrobras is expected to install a total of 18 new FPSOs – 14 of which have already been contracted or are in the process of being contracted. Despite this reinforcement in the new FPSO fleet, the company said that the oil production forecast for 2024 and 2025 was reduced by approximately 0.1 million barrels per day, compared to the previous plan, due to adjustments in the interconnection schedule of wells.
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Post by Blitz on Dec 3, 2022 9:35:46 GMT -5
Brazil's FPSOs results... Brazil: ANP announced October oil production at 4.180 million boe/d, a record for the period brazilenergyinsight.com/2022/12/03/brazil-anp-announced-october-oil-production-at-4-180-million-boe-d-a-record-for-the-period/Total production for October was 4.180 million barrels of oil equivalent per day (boe/d), of which 3.245 million barrels of oil per day (bbl/d) and 148.747 million cubic meters of natural gas per day (m3/d ). In oil, there was an increase of 3.1% compared to the previous month and 16.8% compared to October 2021. In natural gas, the increase was 4% compared to September and 12.9% compared to the same month of the previous year. It was the largest production ever recorded in Brazil, both of oil and natural gas. Until then, the month with the highest oil production had been January 2020, when 3.168 million bbl/d were produced. In the case of natural gas, the highest production had been in September 2022, when 143.070 million m3/d of natural gas were produced. The month of September had also recorded the highest total production: 4.048 million boe/d. Pre-salt Pre-salt production in October was 3.142 million boe/d and corresponded to 75.2% of Brazilian production. 2.459 million bbl/d of oil and 108.61 million m3/d of natural gas were produced through 130 wells. There was an increase of 4.8% in relation to the previous month and 19% in comparison with the same month of the previous year. Use of natural gas In October, the use of natural gas was 98.1%. 55.02 million m3/d were made available to the market and 2.91 million m3/d were burned. There was a reduction in burning of 8.1% compared to the previous month and 33.1% compared to October 2021. Origin of production In October, offshore fields produced 97.6% of oil and 85.1% of natural gas. The fields operated by Petrobras were responsible for 90.83% of the total produced. Production came from 6,119 wells, 497 offshore and 5,621 onshore. Fields and Facilities In October, the Tupi field, in the Santos Basin pre-salt, was the largest producer of oil and natural gas, registering 870.43 thousand bbl/d of oil and 42.35 million m3/d of gas Natural. The facility with the highest oil production was P-77, which produced 166,417 thousand bbl/d in the Búzios and Tambuatá fields. The one with the highest production of natural gas was the FPSO Guanabara, having produced 9.18 million m3/d of natural gas in the Mero field.
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Post by Blitz on Dec 5, 2022 9:30:02 GMT -5
Exxon made a discovery offshore Angola... Yinson, Azule Energy in Angola FPSO Deal 12/5/2022 brazilenergyinsight.com/2022/12/05/yinson-azule-energy-in-angola-fpso-deal/ Malaysian FPSO leasing company Yinson has agreed to start preliminary activities for the provision of an FPSO for Eni, BP JV in Angola, called Azule Energy. Under the agreement with Azule Energy, Yinson will kick off preliminary activities for the provision, operation, and maintenance of a floating, production, storage, and offloading asset for the Agogo Integrated West Hub Development Project in Angola. Azule Energy, formed in August 2022, is Angola’s largest independent equity oil and gas producer. “The APA [Agreement for Preliminary Activities] outlines both parties’ interests in commencing preliminary work in order to meet the project schedule, while finalising firm contract(s) for the project,” Yinson said. According to Yinson, the term of the APA is 60 days with an approximate aggregate value of USD218 million (equivalent to approximately RM956 million). ######### Azule Energy, Angola’s new largest independent oil and gas producer, begins operations Release date: 2 August 2022 www.bp.com/en/global/corporate/news-and-insights/press-releases/azule-energy-angola-new-largest-independent-oil-and-gas-producer-begins-operations.htmlFormation of joint venture, owned 50:50 by bp and Eni, complete Combines both companies’ Angolan upstream, LNG and solar businesses A sunset view of the illuminated PSVM (Plutão, Saturno, Venus and Marte fields) located NE of Block 31 in Angola. The PSVM produces through a converted hull, floating, production, storage and offloading vessel (FPSO). bp and Eni are pleased to confirm that Azule Energy, the new 50/50 independent joint venture combining the two companies’ Angolan businesses, has been officially established. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2 billion barrels equivalent of net resources and growing to about 250,000 barrels equivalent a day (boe/d) of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. Azule Energy will also take over Eni’s share in Solenova, a solar company jointly held with Sonangol, and the collaboration in the Luanda Refinery. Azule Energy boasts a strong pipeline of new projects that are scheduled to come on stream over the next few years, growing organically from exploration discoveries. These include the Agogo Full Field and PAJ oil projects in Blocks 15/06 and 31 respectively, and the New Gas Consortium (NGC), the first non-associated gas project in the country, which will support the energy needs of Angola’s growing economy and strengthen its role as a global LNG exporter. The JV also holds significant exploration acreage in excess of 30,000 square kilometres in Angola’s most prolific basins, allowing it to leverage proximity with existing infrastructure. Azule Energy’s leadership team draws on experience and expertise from both parent companies. The leadership team will report to a six-person board comprising three bp and three Eni representatives, reflecting the ownership share of the company. All bp Angola and Eni Angola staff have joined Azule Energy. Eni and bp share common goals for Azule Energy in achieving environmental and sustainability ambitions. They believe that combining their efforts will create more efficient operations and offer the potential for increased investment, job creation and growth in Angola. They anticipate Azule Energy’s new independent, integrated operating model will unlock significant cost savings, mainly from operational synergies in logistics and technology. “A new, strong entity is born, which combines our experience, skills and technologies with those of our partner bp, putting them at the service of the development of Angolan energy resources, with a priority commitment to environmental protection and the growth of local economy.” Claudio Descalzi, CEO of Eni The JV incorporation takes place after the pending conditions were met, among them having secured a third-party financing of $2.5 billion in the form of Pre-Export Financing, and after receiving regulatory approvals. Bernard Looney, bp’s chief executive, said: “The formation of Azule Energy is an important step for bp, Eni and Angola. Combining our Angolan businesses and drawing on both bp’s and Eni’s expertise, it will continue to safely and efficiently develop Angola’s resilient hydrocarbon resources and pursue new opportunities in oil and gas and other energies. Azule Energy continues our commitment to Angola and will create real value for both the companies and the country.” Claudio Descalzi, CEO of Eni, said: "This is an important milestone for Eni, marking a step forward in Eni’s strategy of enhancing all our best assets. A new, strong entity is born, which combines our experience, skills and technologies with those of our partner bp, putting them at the service of the development of Angolan energy resources, with a priority commitment to environmental protection and the growth of local economy. Adriano Mongini, CEO of Azule Energy, said: “I feel honoured to be the first CEO of the company. Together with a highly competent and motivated leadership team we are committed to develop the full potential of the company portfolio of development and exploration opportunities. With finance discipline and focus on HSE, Azule Energy will maximize the value of the assets for the benefit of Angola and the of the shareholders.” Health, safety and environmental performance, project delivery and production efficiency will be priority areas for the new venture. Azule Energy will maintain access to world-class technologies and best practices through focused technical support from Eni and bp. It will also continue bp’s and Eni’s social investment commitments in Angola. After announcing the intent to form the joint venture in May 2021, bp and Eni worked closely with the Angolan government, and Azule Energy’s formation was subject to all customary governmental and other approvals. Notes to editors Azule Energy is an incorporated joint venture owned equally by Eni and bp that combines the two companies’ Angolan businesses. The main assets now transferred to Azule Energy are: From bp: operated Blocks 18 and 31 offshore Angola, and non-operated stakes in blocks 15, 17, 18/15, 29 and NGC, and a participation in Angola LNG JV. From Eni: operated Blocks 15/06, Cabinda North, Cabinda Centro, 1/14, 28 and soon NGC. In addition, stakes in non-operated blocks 0 (Cabinda), 3/05, 3/05A, 14, 14 K/A-IMI, 15 and participations in Angola LNG and, prospectively, Solenova JVs. In 2021 bp’s total production in Angola was approximately 100,000 boe/d. Eni’s total production in Angola was approximately 100,000 boe/d. Both bp’s and Eni’s equity share of Azule Energy’s production is expected to be approximately 100,000 boe/d. The value of the bp gross assets that are the subject of this transaction as at 31 December, 2021 was approximately $6.8 billion and in the year ended 31 December 2021, the assets generated a pre-tax profit of approximately $1.1 billion. The value of the Eni gross assets that are the subject of this transaction as at 31 December, 2021 was approximately $7.3 billion and in the year ended 31 December, 2021, the assets generated a pre-tax profit of approximately $0.5 billion. Under the terms of the agreement each of bp and Eni will receive a 50% shareholding in Azule Energy. Hydrocarbon production, GHG emissions and reserves will be reported on an equity share basis.
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Post by Blitz on Dec 9, 2022 7:22:14 GMT -5
WATCH: Shell’s giant new FPSO sets off to North Sea on board Boskalis vessel PROJECT & TENDERS December 8, 2022, by Melisa Cavcic www.offshore-energy.biz/watch-shells-giant-new-fpso-sets-off-to-north-sea-on-board-boskalis-vessel/ As China’s Offshore Oil Engineering Company (COOEC) has completed the construction of a circular floating production, storage and offloading (FPSO) vessel destined for Shell’s oil and gas project off the UK, this FPSO is now on its way to the North Sea. COOEC held the delivery ceremony for the Penguins FPSO in Qingdao, east China’s Shandong Province on 29 November 2022. This FPSO was built for Shell’s Penguins oil and gas field located in the UK North Sea, 241 kilometres (150 miles) northeast of the Shetland Islands. The UK-headquartered giant made a final investment decision on the redevelopment of this field in 2018, authorising the construction of the Penguins FPSO, which is reported to be the first new manned installation for Shell in the northern North Sea in almost 30 years. After Offshore Energy reached out to Shell to seek more information about the FPSO’s expected departure date from the Chinese yard, a spokesperson for Shell confirmed on Friday, 1 December 2022 for Offshore Energy that “the FPSO will depart from the Chinese yard imminently.” In addition, Offshore Energy contacted COOEC to obtain more information about the vessel and its expected departure, but no response has been received so far. However, the Chinese player did release a statement on 1 December 2022, highlighting that this FPSO is the largest cylindrical FPSO built by a Chinese company. According to COOEC, the 118-metre-tall vessel – equivalent to a 42-story residential building – has the ability to withstand harsh sea conditions. It weighs 32,000 tonnes and can process 12.75 million barrels of crude oil and 1.24 billion m3 of natural gas per year. This FPSO has a maximum crude storage capacity of 400,000 barrels. Furthermore, COOEC disclosed that the FPSO is composed of more than 1 million parts while 217 sets of large-scale mechanical equipment and more than 17,000 units are integrated on the circular deck with a diameter of 78 meters. Since the start of construction in 2018, the Chinese firm teamed up with partners to overcome the impacts of the global COVID-19 pandemic on material supply chains. “Compared with the conventional ship type, the cylindrical FPSO has more complex production process, more compact space layout, higher degree of integration, and stricter construction technical requirements,” elaborated COOEC. China’s state-controlled media reported that the vessel embarked on its journey last Tuesday. The Penguins FPSO left the Chinese yard on board Boskalis’ semi-submersible heavy transport vessel White Marlin. While it is estimated that the journey to the North Sea will take 55 days, the vessel is expected to stop at a Norwegian yard for commissioning prior to reaching its destination in the UK North Sea. The Penguins field, discovered in 1974, was first developed in 2002 with oil and gas pumped from four drill centres that were tied back to the Brent Charlie platform in the nearby Brent field. Come 2017, after over forty years of operation, Shell started the process of decommissioning the Brent field, including the Brent Charlie platform. Back in 2018, Shell said that the Penguins FPSO would take the place of the Brent Charlie platform, and underscored that the redevelopment of the Penguins field would see an additional eight wells drilled, which would be tied back to the FPSO vessel. The UK player disclosed at the time that oil will be transported via a tanker to refineries while gas will be transported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to the St Fergus gas terminal in northeast Scotland. Once fully functional, the average peak production is expected to be approximately 45,000 boe/d. Meanwhile, COOEC claims that it has delivered many large-scale international energy equipment engineering projects in recent years such as Yamal LNG and Brazil P67/P70 FPSO projects. The company underlined that this demonstrates its “good engineering contract performance capabilities in the field of large-scale floating production units and modular plant construction.” ########
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Post by Blitz on Dec 9, 2022 9:35:44 GMT -5
Westwood: Record Levels of FPS Throughput Capacity to be Sanctioned in 2022 brazilenergyinsight.com/2022/12/09/westwood-record-levels-of-fps-throughput-capacity-to-be-sanctioned-in-2022/#more-50925As we enter the final month of 2022, a review of the floating production system (FPS) market revealed that some E&Ps have been bold with investments in the development of their oil and gas (O&G) reserves, with a total of 1.9 mmboepd (1.3 mmbpd of oil and 3.8 bcfd of gas) of FPS throughput capacity sanctioned year to date (YTD). This represents a 7% increase on 2021, with Westwood anticipating an additional 180 kboepd of FPS throughput capacity to be sanctioned before the end of the year. A total of 13 FPS units have been sanctioned YTD, with an estimated engineering, procurement, and construction (EPC) value of $15 billion, a 9% increase year-on-year. Of these awarded units, ten were floating production, storage and offloading (FPSO) units, three were floating production semi-submersible (FPSS) platforms, whilst no spars nor tension leg platforms (TLPs) were awarded. Although there has been an increase in total FPS EPC contract award value and throughput capacity sanctioned this year compared to 2021, the inflationary cost environment and global supply chain uncertainties have resulted in some E&Ps opting to delay EPC contract awards for major FPS projects previously planned for 2022. At the start of 2022, Westwood anticipated 25 FPS units, with an EPC value of $19 billion to be sanctioned this year. However, delays/changes in development concepts to projects such as Equinor’s Wisting development (Norway), Shell’s Gato do Mato (Brazil), Shell’s Linnorm (Norway), and Santos’ Dorado project (Australia) resulted in a 14% downward revision. The 2022 FPS EPC award value is now anticipated to close at approximately $16.4 billion, driven by 15 units (eight newbuilds, two conversions and five upgrades/redeployments). It is pertinent to state that the EPC contract value for Petrobras’ P-80, P-82, and P-83 were higher than initially forecasted, hence, reducing the impact of delayed projects on the 2022 EPC value. Westwood anticipates an upgrade to Cenovus Energy’s Sea Rose FPSO unit, and an EPC contract for CNOOC’s Deepwater 2 FPSS could still be sanctioned before the end of 2022. Despite major project delays, 2022 will have the highest FPS throughput capacity sanctioned since 2010. FPS throughput capacity by EPC contract award year Source: PlatformLogix, Westwood Analysis Looking forward to 2023, Westwood estimates FPS throughput capacity to be sanctioned to total 2.2 mmboepd, with an EPC award value of $16 billion. This is expected to be driven predominantly by activities in Latin America and West Africa. Major EPC awards anticipated in 2023 include Petrobras’ P-81, P-84 and P-85 FPSOs, as well as Equinor’s Pao de Acucar unit offshore Brazil. In Guyana, Modec recently signed the front-end engineering and design (FEED) contract for the fifth Stabroek FPSO unit to be deployed on ExxonMobil’s Uaru. However, the EPCI contract award anticipated in 2023 is subject to governmental approvals of the field development plan and a final investment decision by Exxon. Other FPS units expected to watch in 2023 include Azule Energy’s Agogo FPSO (Angola), TotalEnergies’ Cameia FPSO (Angola), Eni’s Baleine FPSO (Ivory Coast), and Woodside Energy’s Trion FPSS (Mexico). Woodside expects bid submission for the Trion unit in 1Q 2023 after the operator delayed FID from 2022, citing the need to optimize the development and execution plan, cost, and development schedule. Supply chain inflationary pressure remains a concern. Over the past five years, cost deflation, simplification, and standardization have seen the EPC cost of FPSO units fall dramatically, averaging $7,950/boepd of throughput capacity. This is a 38% discount compared to the highs of $12,795/boepd observed over the 2013/14 period. However, an increase in the volume of active EPC tenders and an uptick in industry cost has resulted in average 2022 EPC costs of $9,310/boepd. This represents a 17% increase over the 2017-2021 period and a 32% increase compared to activities in 2020 during the peak of the Covid-19 pandemic. Considering five-year contracting periods between 2012 and 2026, forecast FPS throughput capacity to be sanctioned over the 2022-2026 period represents a 36% increase compared to the preceding five-year period and an 87% growth on the 2012-2016 period. However, rising costs are causing significant delays to major projects. Furthermore, concerns over shipyard capacity remain, as China’s ‘Zero-Covid’ policy could exacerbate supply chain constraints following uncertainties created due to the war in Ukraine. Should an uptick in industry costs continue, previously delayed projects such as Equinor’s Rosebank (UK) and Bay Du Nord development (Canada), Shell’s Bonga SW (Nigeria) and TotalEnergies’ Block 58 development could experience further delays, thereby impacting the total FPS throughput capacity to be sanctioned over the forecast period.
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Post by bjspokanimal on Dec 9, 2022 11:04:52 GMT -5
I'm starting to think you have stock in some FPSO interests, blitz.
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Post by Blitz on Dec 9, 2022 17:08:34 GMT -5
I'm starting to think you have stock in some FPSO interests, blitz. If ship yards were not so tight and most are Singapore or in China... I would like to find one worthy of buying. That said... per your guidance related to FPSOs... they are the 'P' in offshore E&P. Without them and shuttle tankers, why drill offshore. Look at offshore Brazil and Petrobras' plans. They have big plans to increase offshore production. Guyana will need more. India will need more. The North Sea needs more, the Norweigian Sea needs more, Egypt will need more... to name but a few. For now, I see all these areas as sucking up drillships or semi-subs and the proof of concept is, following the FPSOs.
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Post by Blitz on Dec 12, 2022 8:16:34 GMT -5
A person could guess Brazil plans to be doing a lot of offshore E&P... Ibama green lights start of P-71 production and authorizes installation of FPSO Marechal Duque de Caxias brazilenergyinsight.com/2022/12/10/ibama-green-lights-start-of-p-71-production-and-authorizes-installation-of-fpso-marechal-duque-de-caxias/(TN) The Brazilian Institute of the Environment (Ibama) has granted two important licenses to Petrobras. The first authorizes the start of operations of FPSO P-71 in the Itapu field, in the Santos Basin pre-salt. The document will be valid for eight years. Petrobras expects to start operating the platform in December. As a reminder, the P-71 already left for the Itapu field in October, after going through commissioning activities at the Jurong Aracruz shipyard, in Espírito Santo. The vessel will be able to produce up to 150,000 barrels of oil and 6 million cubic meters of gas daily. In addition, the P-71 will be capable of storing 1.6 million barrels of oil. In addition, Ibama also granted the installation license for the FPSO Marechal Duque de Caxias, which will be used in the Mero field, also in the Santos Basin pre-salt. The new Mero platform, which is still under construction, will have a processing capacity of 180,000 barrels of oil and 12 million m³ of gas per day. The unit should only produce the first oil in 2024. Finally, Petrobras also received a license from Ibama authorizing the start of seismic research in the Aram block, in the Santos Basin. The activity can be carried out using the vessel M/V Artemis Odyssey, from Westcon Geo, and the node installation ships Siem Dorado, from Siem Offshore, and Boka Tiamat, from Topaz Energy and Marine.
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Post by Blitz on Dec 12, 2022 8:22:14 GMT -5
Holder of world’s 17th largest oil reserves on course to add more barrels By OilNOW - December 12, 2022 oilnow.gy/featured/holder-of-worlds-17th-largest-oil-reserves-on-course-to-add-more-barrels/ An FPSO is pictured at the ExxonMobil-operated Stabroek Block offshore Guyana. Ten such vessels are expected to be producing oil offshore the South American country by the end of the decade.
With no known commercial hydrocarbons just seven years ago, Guyana is now the holder of the 17th largest oil reserves in the world. Aggressive exploration activities off the country’s coast, mainly by US oil major ExxonMobil, have seen major discoveries being made each year since 2015, which in total, now surpass 11 billion barrels of oil equivalent. But analysts say this is just the tip of the iceberg. The best exploration year yet for Exxon and the Stabroek Block co-venturers is 2022, according to Hess’ Vice President – Exploration and Production, Timothy Chisholm. Hess, a partner in the development of Stabroek, revealed that the 11 billion resource count has not yet incorporated the complete results for commercial discoveries made in 2022. Chief Executive Officer of Hess, John Hess, said the count will see a “major upgrade” when the results for discoveries announced so far for 2022 are fully analysed. Hess also said in June that the Stabroek Block is still in the early innings of its exploration story. The co-venturers continue to see multi-billion-barrel potential in the block. This outlook has been shared by independent analysts. Co-director for Americas Market Intelligence (AMI) Energy Practice, Arthur Deakin, said in February that the firm expects there to be more than 20 billion barrels of oil-equivalent in Stabroek, with a hefty portion of gas that could support another profitable export avenue for Guyana. Dr. Daniel Yergin, Vice President at IHS Markit said in February that the total resource is significantly high with much room for further increases. IHS Markit estimated at the time that 13.5 billion barrels had been proven, and that the yet-to-find potential stood at 9.3 billion barrels of oil-equivalent. “That makes the ultimate recovery total something like 23 billion of oil recovery and we believe this number is set to raise as more plays and sub-plays are tested,” Yergin said. Chief Executive Officer and Chairman of ExxonMobil Corp. called the success at Stabroek “unmatched” in modern history. Senior Vice President and Head of Latin America and the Caribbean for Rystad Energy, Schreiner Parker, told a forum in Georgetown in August that the Stabroek block is one of the most unprecedented exploration blocks of all time. “If you think about the typical success rate for exploration, it’s usually around 20% meaning that out of every five exploration wells that you drill, you’ll encounter hydrocarbons in one of those exploration wells,” Parker said. In terms of exploration at Stabroek, he explained that it has been almost the complete opposite, noting that there have been few dry holes drilled versus the number of discoveries. More than 30 commercial discoveries have been made there already. ExxonMobil is currently executing a 25-well exploration campaign which is expected to conclude in the first half of 2023. It has applied for approvals to drill another 35 exploration wells in the Stabroek Block, starting in the second half of 2023 and concluding in 2028. Over at the Kaieteur and Canje blocks, also operated by ExxonMobil, 24 wells – 12 each – are planned and in the process of securing regulatory approvals. Guyana also recently launched an auction for 14 blocks, in hopes of adding to the exploration success outside of the Stabroek Block. Three deepwater and 11 shallow water blocks are up for grabs, with new terms that grant Guyana a great share of the value of oil production. President Dr. Mohamed Irfaan Ali said Friday that the potential reserves at stake are at 25 billion barrels. Gerard Walsh, Chairman of Westmount Energy Limited says the market will be hungry for prime acreage offshore Guyana. This, he said, is irrespective of the fact that significant oil discoveries have been solely confined thus far to the Stabroek Block. An upgrade to Guyana’s petroleum resource count, in line with analysts’ expectations, could see the country surpassing Brazil and Algeria which are in 15th and 16th places for world’s largest reserves. With the economic boom brought on by these successes in Guyana, the country is uniquely positioned to be the fastest growing economy of the decade.
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Post by Blitz on Dec 16, 2022 9:39:14 GMT -5
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Post by Blitz on Dec 16, 2022 12:40:27 GMT -5
Westwood: Highest FPS throughput capacity since 2010 greenlighted in 2022 brazilenergyinsight.com/2022/12/16/westwood-highest-fps-throughput-capacity-since-2010-greenlighted-in-2022/#more-51109 (OET) Westwood Global Energy, an energy market research and consultancy firm, has outlined that 2022 will have the highest floating production system (FPS) throughput capacity sanctioned since 2010, despite major project delays caused by multiple factors, including the supply chain inflationary pressure, which remains a concern in the future as well. Within its review of the FPS market, Westwood recently revealed that some exploration and production (E&P) companies have been “bold with investments” in the development of their oil and gas reserves, with a total of 1.9 mmboepd – 1.3 mmbpd of oil and 3.8 bcfd of gas – FPS throughput capacity sanctioned year to date (YTD). As this represents a 7 per cent increase from 2021, the energy market research provider anticipates an additional 180 kboepd of FPS throughput capacity to be sanctioned before year-end. Furthermore, a total of 13 FPS units have been sanctioned so far this year, with an estimated engineering, procurement and construction (EPC) value of $15 billion, a 9 per cent increase year-on-year. Ten of these units were floating production, storage and offloading (FPSO) units, three were floating production semi-submersible (FPSS) platforms, whilst no spars nor tension leg platforms (TLPs) were awarded, highlighted Westwood. Despite an increase in total FPS EPC contract award value and throughput capacity sanctioned this year compared to 2021, the inflationary cost environment and global supply chain uncertainties have resulted in some E&Ps opting to delay EPC contract awards for major FPS projects, which were previously planned for 2022. Previously, Westwood anticipated 25 FPS units, with an EPC value of $19 billion will be sanctioned this year. However, delays and changes in development concepts to projects such as Equinor’s Wisting development in Norway, Shell’s Gato do Mato in Brazil, Shell’s Linnorm in Norway and Santos’ Dorado project in Australia resulted in a 14 per cent downward revision. As a result, the 2022 FPS EPC award value is now anticipated to close at approximately $16.4 billion, driven by 15 units, out of which eight are newbuilds, two are conversions and five are upgrades/redeployments. Courtesy of Westwood Moreover, Westwood underscored that the EPC contract value for Petrobras’ P-80, P-82 and P-83 were higher than initially forecasted, reducing the impact of delayed projects on the 2022 EPC value. The energy market research firm anticipates an upgrade to Cenovus Energy’s Sea Rose FPSO unit, and an EPC contract for CNOOC’s Deepwater 2 FPSS could still be sanctioned before the end of 2022. How things stand for 2023 Regarding its outlook for 2023, Westwood estimates FPS throughput capacity to be sanctioned to total 2.2 mmboepd, with an EPC award value of $16 billion. Driven predominantly by activities in Latin America and West Africa, the major EPC awards anticipated in 2023 include Petrobras’ P-81, P-84 and P-85 FPSOs, as well as Equinor’s Pao de Acucar unit offshore Brazil. While Modec recently signed the front-end engineering and design (FEED) contract in Guyana for the fifth Stabroek FPSO unit to be deployed on ExxonMobil’s Uaru, the EPCI contract award anticipated in 2023 is subject to governmental approvals of the field development plan and a final investment decision by the U.S. energy giant. Meanwhile, Westwood pointed out that other FPS units to watch in 2023 include Azule Energy’s Agogo FPSO in Angola, TotalEnergies’ Cameia FPSO also in Angola, Eni’s Baleine FPSO in Ivory Coast and Woodside Energy’s Trion FPSS in Mexico. Citing the need to optimise the development and execution plan, cost, and development schedule, Woodside delayed the FID from 2022 and expects bid submission for the Trion unit in 1Q 2023. Rising costs continue to plaque projects Westwood further underlined that cost deflation, simplification and standardisation have seen the EPC cost of FPSO units fall dramatically over the past five years, averaging $7,950/boepd of throughput capacity. This is a 38 per cent discount compared to the highs of $12,795/boepd observed over the 2013/14 period. However, an increase in the volume of active EPC tenders and an uptick in industry cost have resulted in average 2022 EPC costs of $9,310/boepd, based on Westwood’s data. This represents a 17 per cent increase over the 2017-2021 period and a 32 per cent increase compared to activities in 2020 during the peak of the Covid-19 pandemic. Bearing in mind five-year contracting periods between 2012 and 2026, the energy market research player emphasised that the forecast for the FPS throughput capacity to be sanctioned over the 2022-2026 period represents a 36 per cent increase compared to the preceding five-year period and an 87 per cent growth on the 2012-2016 period. In spite of this growth, rising costs are causing significant delays to major projects, says Westwood. Additionally, concerns over shipyard capacity remain, as China’s zero-Covid policy could exacerbate supply chain constraints, following uncertainties created due to the war in Ukraine. If an uptick in industry costs continues, previously delayed projects such as Equinor’s Rosebank in the UK and Bay Du Nord development in Canada, Shell’s Bonga SW in Nigeria and TotalEnergies’ Block 58 development could experience further delays. Westwood concludes that if these projects are postponed, this would impact the total FPS throughput capacity to be sanctioned over the forecasted period.
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Post by Blitz on Dec 18, 2022 9:48:59 GMT -5
Petrobras to add 18 FPSOs in next five years By OilNOW - December 18, 2022 oilnow.gy/featured/petrobras-to-add-18-fpsos-in-next-five-years/Brazil’s Petrobras plans to place 18 floating production, storage, and offloading (FPSO) vessels offshore Brazil in the next five years, according to its 2023-2027 Strategic Plan. The vessels’ capacities will range from 70,000 to 225,000 barrels of oil per day (bpd). In 2023, six vessels are expected, with combined capacity of 630,000 bpd. In 2024, three vessels are expected, with combined capacity of 505,000 bpd. In 2025, three vessels are expected, with combined capacity of 540,000 bpd. In 2026, two vessels are expected, with combined capacity of 450,000 bpd. In 2027, five vessels are expected, with combined capacity of 711,000 bpd. Most of them are earmarked for pre-salt fields. The Plan makes few adjustments to the company’s previous FPSO vision for the 2023-2026 period in its 2022-2026 Plan. Norwegian consultancy, Rystad Energy, had projected earlier this year that while many offshore producers will see reduced output through 2035, Brazil’s will increase to almost 5 million bpd. With the 2027 FPSOs planned, Brazil is likely to exceed the 5 million bpd mark. Present oil production levels are just above 3 million bpd. Guyana was noted as a distant second in Rystad’s project, as it is expected to achieve offshore output about 1.2 million bpd by 2027. Petrobras also plans to drill 42 wells in the period 2023-2027, to add to its reserves, among the largest in the world.
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Post by Blitz on Dec 18, 2022 9:51:54 GMT -5
This means floaters will be working there doing E&P to support those FPSOs for another 5 years at least...
Petrobras to add 18 FPSOs in next five years
By OilNOW - December 18, 2022 oilnow.gy/featured/petrobras-to-add-18-fpsos-in-next-five-years/
Brazil’s Petrobras plans to place 18 floating production, storage, and offloading (FPSO) vessels offshore Brazil in the next five years, according to its 2023-2027 Strategic Plan.
The vessels’ capacities will range from 70,000 to 225,000 barrels of oil per day (bpd).
In 2023, six vessels are expected, with combined capacity of 630,000 bpd.
In 2024, three vessels are expected, with combined capacity of 505,000 bpd.
In 2025, three vessels are expected, with combined capacity of 540,000 bpd.
In 2026, two vessels are expected, with combined capacity of 450,000 bpd.
In 2027, five vessels are expected, with combined capacity of 711,000 bpd.
Most of them are earmarked for pre-salt fields. The Plan makes few adjustments to the company’s previous FPSO vision for the 2023-2026 period in its 2022-2026 Plan.
Norwegian consultancy, Rystad Energy, had projected earlier this year that while many offshore producers will see reduced output through 2035, Brazil’s will increase to almost 5 million bpd. With the 2027 FPSOs planned, Brazil is likely to exceed the 5 million bpd mark. Present oil production levels are just above 3 million bpd.
Guyana was noted as a distant second in Rystad’s project, as it is expected to achieve offshore output about 1.2 million bpd by 2027.
Petrobras also plans to drill 42 wells in the period 2023-2027, to add to its reserves, among the largest in the world.
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Post by Blitz on Dec 18, 2022 10:04:53 GMT -5
Here's the range for how long it takes to drill an offshore well: Excerpt: www.diamondoffshore.com/offshore-drilling-basics#:~:text=The%20oil%20company%20chooses%20the,the%20complexity%20of%20the%20project. "the operation, which may take as little as 15 days or as long as 12 months, of round-the-clock, seven-days-per-week operation to drill a single well depending on the complexity of the project." ///////// Drilling an offshore well can take three to four months and cost $120 million to $160 million per well, with the most complex drilling projects taking as long as a year. Offshore wells are significantly costlier than those on land, with wells off the coast of West Africa costing up to 30 times more than those drilled into US shale. www.investopedia.com/ask/answers/061115/how-long-does-it-take-oil-and-gas-producer-go-drilling-production.asp//////// Deepwater Offshore Brazil/Guyana could be busy a very long time if the GoM can be used as example... How many offshore wells have been drilled in the Gulf of Mexico: How many wells have been drilled in the Gulf of Mexico? Current Gulf of Mexico Oil Drilling and Well Production There have been nearly 90,000 offshore wells drilled in the GOM to date. Here's and article with just everything you'd like to know GoM E&P numbers: Excerpt: FIGURE 1 | Map of U.S. Gulf of Mexico Oil Production Areas FIGURE 3 | Wells Spud Through Time in the U.S. Gulf of Mexico www.enverus.com/solutions/energy-analytics/ep/prism/global/gulf-of-mexico/
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Post by Blitz on Dec 18, 2022 10:17:07 GMT -5
Looks like Brazil wants to change this trend to rising well counts and production. The link has charts. Number of oil and gas wells in Brazil 2010-2021, by location Published by Bruna Alves - Aug 8, 2022 www.statista.com/statistics/1058726/brazil-number-oil-wells/ The number of oil and gas wells in Brazil has been mostly decreasing in recent years. In 2021, the number of wells in the country amounted to 6,954, down from over 9,000 wells in 2014. More than 89 percent of wells were located onshore. That same year, Brazil's offshore crude oil production stood at around 1.03 million barrels. Number of oil and gas wells in Brazil from 2010 to 2021, by location - Chart /////////// Brazil offshore drilling market - The upcycle gains momentum 02 December 2022 Carlos Rocha Eduardo de Freitas www.spglobal.com/commodityinsights/en/ci/research-analysis/brazil-offshore-drilling-market-the-upcycle-gains-momentum.htmlThe global offshore drilling market is picking up strongly since the past year and the uptick accelerated during the current year. The offshore drilling segment, which is commonly seen as one of the most critical components of the drilling value chain, is getting stronger and gradually tighter. This is underscored by trends observed across key indicators such as global marketed utilization, average contract duration, and day rates across both shallow and deepwater segments. All of them experienced an inflection point around 2018 and are consistently growing despite minor retreats during the COVID-19 outbreak. The Brazilian offshore drilling market constitutes one of the most important demand regions for high-specification floaters - the country is within the coveted "golden triangle" of the global offshore drilling market alongside GoM and West Africa. And the recent trends in the Brazilian rig market mimic the rebound and gradual tightening observed worldwide: day rates are increasing alongside contract duration as shown in the following chart. There also growing signs of bottlenecks across the specialized drilling supply chain and local labor market: from unprecedented lead times for specialized drilling equipment to concerns around the availability of experienced and qualified professionals, these constraints pose risks to current and future drilling projects. The market is expected to level off at some point, but the main question revolves around how fast this balance can be achieved. After all, this is a highly capital-intensive industry, with sharp and unpredictable cycles, which was heavily battered for most of the past decade and is now experiencing a resurgence amid a controversial duality of energy transition and energy security. Long-term fundamentals and a favorable risk-reward scenario perceived by major industry players are key to spurring additional investment across the supply chain and relieving any existing or eventual bottlenecks From a demand standpoint, we expect as many as 100 offshore wells to be drilled yearly on average until 2026, which could push the demand for offshore drilling rigs to the range of 35 to 40 units between 2025 and 2026. Petrobras has always been the key customer and will continue to play such a role with 14 production units planned to come onstream by 2026, which should account for the bulk of development wells expected to be drilled in the country over the next five years. However, IOCs and local independents should also have a growing important role in the overall local customer base for offshore drilling services. We expect between 30-35% of both development and exploration wells to be drilled by Operators other than Petrobras by 2026. This is an interesting trend since the Brazilian NOC accounted for over 80% of all offshore wells drilled in the country between 2016-21. Therefore, higher diversification across the local drilling customer base is expected over the next years. On the exploration side, there is a steep decline in the number of offshore exploration wells drilled in the country since 2011. There are several factors behind this trend, both external and internal, such as the global oil and gas industry 2014-downturn and the relatively long hiatus in local offshore bidding rounds from 2009-13. Campos and Santos keep their prominence around local exploration efforts and they both account for over 85% of offshore new field wildcats drilled since 2016, mostly in the pre-salt polygon. Noteworthy exploration activities and discoveries in 2022 include Alto de Cabo Frio Central and the NFW Bob-1 drilled by Shell in the Campos basin. A highly anticipated exploratory campaign is Petrobras' plans for the Equatorial Margin, particularly the Morpho-1 wildcat expected to be spudded in the Foz do Amazonas basin between the end of 2022 and the beginning of 2023. Development wells commonly account for most wells drilled, but it's also worth noticing that key factors such as the high productivity of the pre-salt wells combined with technological advancements contributed to the reduction observed in the total number of development wells built since 2014 without compromising the country's production output. The local offshore rig market is dominated by a few local players with substantial contracts held by major international drilling contractors as well. The common ground shared by active local players is the fact they own and operate modern units capable of working in water depths of over 2,000 m and featuring state-of-the-art equipment and technology. However, a key aspect commonly held by drilling contractors operating in Brazil is the ability to cope with strict local regulatory requirements, some of which are unique to the Brazilian reality and usually require minor equipment modification and upgrades, which are also set forth by the customers in tenders and contracts. All in all, the local offshore drilling market is set to grow under ambitious development programs planned for the next years despite uncertainties around changes to the existing oil and gas local policies combined with possible changes to Petrobras' strategy that could be implemented by the new government of the recently elected president Lula. For more details, we invite the reader to access our full report "Brazil offshore drilling market -Issue 02: The upcycle gains momentum". ***
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Post by Blitz on Dec 19, 2022 10:18:23 GMT -5
This will require floaters and FPSOs... QatarEnergy, TotalEnergies and Petronas win offshore exploration block in Brazil brazilenergyinsight.com/2022/12/19/qatarenergy-totalenergies-and-petronas-win-offshore-exploration-block-in-brazil/#more-51139A consortium of three oil and gas giants – Qatar’s QatarEenergy, France’s TotalEnergies, and Malaysia’s Petronas – have been awarded an offshore exploration block during the first cycle of Brazil’s open acreage under a production sharing regime bid held in Rio de Janeiro. QatarEnergy disclosed on Monday that, together with TotalEnergies and Petronas, it has been awarded the Agua-Marinha Production Sharing Contract (PSC), under the first cycle permanent offer round, by Brazil’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP). Covering an area of 1,300 square kilometres, the Agua-Marinha block is located in water depths of about 2,000 meters off the coast of Rio de Janeiro in the prolific Campos Basin. This acquisition is expected to close in the first half of 2023. Upon completion, Qatar’s state-owned oil and gas giant will hold a 20 per cent working interest in this block, alongside the block’s operator Petrobras (30 per cent), TotalEnergies (30 per cent) and Petronas Petroleo Brasil (20 per cent). Commenting on this, Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, remarked: “We are pleased to achieve this latest successful joint bid, which adds further highly prospective acreage to our upstream portfolio in Brazil, and particularly in the prolific Campos Basin.” According to QatarEnergy, this acquisition further strengthens its role as one of the leading upstream players in Brazil, where it already holds working interests in two producing fields and numerous exploration blocks. “I wish to take this opportunity to thank the ANP and the Brazilian authorities for this opportunity and for their ongoing support,” added Al-Kaabi. Regarding QatarEnergies’ other recent activities, it is worth noting that the company disclosed a successful bid last month for Parcel 8 of the Orphan Basin, offshore the province of Newfoundland and Labrador in Canada. In a separate statement, TotalEnergies confirmed the award of the Agua Marinha block, elaborating that the entry into this block follows the entry into two blocks, S-M-1815 and S-M-1711, in the South Santos basin during the third cycle of the permanent offer that took place on 13 April 2022. Kevin McLachlan, Senior Vice President, Exploration of TotalEnergies, stated: “TotalEnergies is pleased to expand its presence in the Campos Basin with this new exploration block, alongside three strategic partners. This is in line with our strategy to focus exploration on selected high potential basins which can deliver material low cost, low carbon intensity resources.” The French oil major’s Brazilian exploration and production portfolio encompasses ten assets, of which four are operated. In 2021, the firm’s production in Brazil averaged 49,000 barrels of oil equivalent per day and this figure is expected to exceed 100,000 in 2022. In December 2021, TotalEnergies, bidding in the Transfer of Rights Surplus round, was awarded two new non-operated PSCs on the Atapu Surplus (22.5 per cent) and Sépia Surplus (28 per cent) units, which were signed in late April 2022. Meanwhile, Petronas also corroborated that its subsidiary, Petronas Petróleo Brasil (PPBL) has won an interest in the Agua Marinha exploration block, outlining that the result of the bid for the pre-salt acreage area was announced by the ANP in a live ceremony on 16 December. Mohd Redhani Abdul Rahman, Petronas Vice President of Exploration, said: “We are truly thrilled by the favourable outcome of the bid round. This success demonstrates our competitive edge in sustainably developing and monetising assets in the Campos Basin. Petronas remains focused to unlock more value from the assets with its partners alongside the host authorities.” In addition, the firm holds participating interests in the Tartaruga Verde – BM-C-36 Concession – and Module III of the Espadarte – Espadarte Concession – deepwater fields, as well as three deepwater exploration blocks, C-M-541, C-M-661 and C-M-715, in the Campos Basin. Recently, an oil discovery was announced at the 4-BRSA-1386D-RJS well in the pre-salt Sépia oil field in the Santos Basin, where QatarEnergy, TotalEnergies and Petronas hold non-operated interest while Petrobras acts as the operator.
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Post by bjspokanimal on Dec 19, 2022 14:58:48 GMT -5
A lot of this is in the pre-salt regions where it's hard to legitimately call a well a "wildcat" anymore. My hopes are on the wildcats they're looking at in the equatorial margin as success there could open up an entirely new geography along the extensive Brazilian coastline.
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Post by Blitz on Dec 27, 2022 9:24:35 GMT -5
FPSO Anita Garibaldi arrived at the Jurong shipyard for commissioning activities brazilenergyinsight.com/2022/12/27/fpso-anita-garibaldi-arrived-at-the-jurong-shipyard-for-commissioning-activities/Modec’s FPSO Anita Garibaldi is already in Brazilian waters. The platform vessel arrived at the Jurong Aracruz shipyard, in Espírito Santo, where it will undergo commissioning activities, in addition to regulatory inspections and operational tests. Right after these final preparatory works, the unit will leave for the Marlim field, in the Campos Basin. Start-up is scheduled for the third quarter of 2023. The vessel has the capacity to produce up to 80,000 barrels of oil per day (bpd) and process up to 7 million cubic meters of natural gas per day. As a reminder, FPSO Anita Garibaldi is part of the Marlim and Voador Revitalization Project. Petrobras’ idea is to connect the new platform to 43 wells, with peak production expected for 2026. The Marlim Revitalization Project plans to replace the nine platforms currently operating in the Marlim and Voador fields (P-18, P-19, P-20, P-26, P-32, P-33, P-35, P-37 and P-47) by the new FPSOs Anita Garibaldi and Anna Nery.
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Post by Blitz on Dec 27, 2022 9:26:11 GMT -5
Enauta raises BR$ 1.4 billion in debentures to finance the deployment of new FPSO in the Atlanta field brazilenergyinsight.com/2022/12/26/enauta-raises-br-1-4-billion-in-debentures-to-finance-the-deployment-of-new-fpso-in-the-atlanta-field/(PN) The company concluded its first issue of simple debentures, in a restricted public offering. The transaction totaled BR$1.4 billion, of which approximately BR$737 million were First Series debentures and approximately BR$663 million were Second Series debentures, both non-convertible into shares. The funds raised will be used by the company in the development of the Definitive System of the Atlanta field, in the Santos Basin. The amount will also be used to reinforce the oil company’s working capital. As a reminder, the Atlanta field currently operates with an Early Production System, through FPSO Petrojarl I. For the future, the company intends to inaugurate a Definitive System, with FPSO OSX-2, whose operation should start in mid- 2024. In February of this year, the oil company announced the final investment decision in the Definitive System, in the amount of US$ 1.2 billion. “We completed our first issue of debentures, gaining access to the resources needed to finance the Atlanta project and improve our capital structure. This is another step towards positioning Enauta as the Brazilian independent with the most balanced portfolio and with the greatest potential for generating value”, evaluated Enauta’s CEO, Décio Oddone. Debentures are debt securities by which a company offers credit rights to investors. The company detailed that the net proceeds obtained from the first series bonds will be used exclusively for reimbursement and/or future payment of expenses, expenses or debts related to the implementation and development of the Definitive System of the Atlanta Field. The first series papers will have a tax incentive, so that their holders will be entitled to tax benefits. The proceeds from the issuance of the second series will be used exclusively to reinforce working capital, as well as other general corporate purposes.
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