ONEOK, Inc. (NYSE: OKE) today announced that its Saguaro Connector Pipeline subsidiary has filed a Presidential Permit application with the Federal Energy Regulatory Commission (FERC) to construct and operate facilities for the exportation of natural gas at a new international border-crossing at the U.S. and Mexico border in Hudspeth County, Texas.
The proposed border facilities would connect upstream with a potential intrastate natural gas pipeline, the Saguaro Connector Pipeline, which would be designed to transport natural gas from ONEOK's existing WesTex intrastate natural gas pipeline system in the Permian Basin in West Texas to Mexico. Additionally, the proposed border facilities would connect at the International Boundary with a new pipeline under development in Mexico for delivery to an export facility on the West Coast of Mexico.
The potential Saguaro Connector Pipeline would consist of approximately 155 miles of 48-inch-diameter natural gas pipeline originating at the Waha Hub in Pecos County, Texas. The ultimate design capacity of the potential pipeline would be approximately 2.8 billion cubic feet per day. Final investment decision on the potential pipeline is expected by mid-2023.
ONEOK, Inc. (pronounced ONE-OAK) (NYSE: OKE) is a leading midstream service provider and owner of one of the nation's premier natural gas liquids (NGL) systems, connecting NGL supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers and an extensive network of natural gas gathering, processing, storage and transportation assets.
Friday 30 December 2022
The Njord field upgraded and ready for another 20 years
Production from the Njord field in the Norwegian Sea resumed at 16.30 on 27 December, following an upgrading project in which both the platform and the floating storage and offloading vessel (FSO) were brought ashore.
The field is now back on stream, ensuring secure and stable energy supplies to Europe.
Both the platform and the FSO have undergone extensive upgrades, and the project has a Norwegian content of more than 90 percent. Aker Solutions has had the main responsibility for the platform engineering and upgrading. Brevik Engineering has carried out the engineering work for the FSO, which has been upgraded by Aibel.
“I am proud that we and our partners, Wintershall Dea and Neptune Energy, have now got this truly unique project across the finish line. This is the first time a platform and a FSO have been disconnected from the field, upgraded, and towed back, and we have now doubled the field’s life.It has been a big and challenging job, partly performed during a pandemic, and I want to thank everyone who has contributed. The Njord field will now deliver important volumes to the market for another two decades," says Geir Tungesvik, Equinor's executive vice president for Projects, Drilling & Procurement.
Coming on stream in 1997, the Njord installations were initially designed to remain in operation until 2013. However, there were large volumes left in the ground, in addition to discoveries nearby, such as Hyme which came into operation in 2013, and others that can be produced and exported via Njord.
The platform and FSO were brought ashore in 2016 after 19 years of production. In 2017 and 2018, upgrading contracts were awarded for the two installations. The Njord A platform was upgraded at Stord, where it was constructed in the 90s. The Njord Bravo FSO was inspected prior to upgrade and prepared for tow-out in Kristiansund, whereas the refurbishment was carried out in Haugesund.
“Our ambition is to produce about the same volume from Njord and Hyme as we have produced so far, more than 250 million barrels of oil equivalent," says Kjetil Hove, Equinor's executive vice president for Exploration & Production Norway.
10 new wells will be drilled at Njord from an upgraded drilling facility, new discoveries have been made at the outer edges of Njord, and more exploration will be carried out in the surrounding area.In addition, the platform and FSO have been prepared to receive production from two new subsea fields, Bauge and Fenja, with a total of 110 million barrels of recoverable resources.
“This is illustrative of our strategic work on the NCS to extend the fields’ productive life and tying back new discoveries to existing infrastructure, while reducing the climate footprint from the production," says Hove.
According to plans the Njord field will in a few years receive power from shore via the Draugen platform in the Norwegian Sea and be partially electrified. This will reduce the annual CO2 emissions by about 130,000 tonnes.
Production from the Njord field was initially supposed to resume two years ago. However, the upgrading project has been more challenging than expected, and the project was hard hit by the Covid-19 pandemic. This has also put an upward pressure on costs. Capital expenditures total just over NOK 31 billion (2022), compared with the original NOK 17 billion in the plan for development and operation. However, the project is profitable with oil prices far lower than today.
Sempra Infrastructure Receives Export Licenses for Two LNG Projects
Sempra Infrastructure, a subsidiary of Sempra (NYSE: SRE) (BMV: SRE), today announced that Energía Costa Azul, S. de R.L. de C.V. (ECA LNG) and Vista Pacifico, S.A.P.I. de C.V. (Vista Pacifico LNG) received authorization from the U.S. Department of Energy (DOE) to re-export U.S.-sourced liquefied natural gas (LNG) from Mexico to non-Free Trade Agreement (FTA) nations. The DOE's significant action is an important milestone for these two development projects, which now are each one step closer to supporting the world's energy security and environmental goals.
"Advancing new infrastructure investments is critical to supporting the energy needs of America's allies, and we are grateful for the leadership of the Biden Administration, U.S. Energy Secretary Jennifer Granholm, and various Congressional stakeholders—including Sens. Joe Manchin, Ted Cruz and John Cornyn. These export projects are expected to support efforts across the Indo-Pacific region to diversify energy supplies while transitioning away from coal in power production," said Justin Bird, CEO of Sempra Infrastructure. "They are also expected to help strengthen U.S. trading relationships, as well as create new jobs and boost the U.S. and Mexico economies."
Under the permits granted by DOE, Vista Pacifico LNG is authorized to re-export up to 200 billion cubic feet per year (Bcf/yr) of LNG from U.S.-sourced natural gas from the project under development in Topolobampo, Sinaloa, Mexico to any country with which the United States does not have an FTA requiring national treatment for trade in natural gas. Vista Pacifico LNG is projected to be a mid-scale facility with approximately 3.5 million tons per annum (Mtpa) of export capacity. Sempra Infrastructure is advancing the development of Vista Pacifico LNG in collaboration with Mexico's Federal Electricity Commission (CFE), as previously announced.
The DOE also increased the authorized export volumes of ECA LNG Phase 2, permitting it to re-export up to 636 Bcf/yr of LNG from U.S.-sourced natural gas from the proposed project in Ensenada, Baja California, Mexico to non-FTA nations. Both permits are applicable for the period beginning on the date of first commercial re-export through December 2050.
The proposed ECA LNG Phase 2 is expected to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. ECA LNG Phase 1 received non-FTA export authorization in 2019 and is currently under construction with commercial operations expected in 2025.
Development of ECA LNG Phase 2 and Vista Pacifico LNG is contingent upon completing the required commercial agreements, securing all necessary permits, obtaining financing, and reaching a final investment decision, among other factors.
"Advancing new infrastructure investments is critical to supporting the energy needs of America's allies, and we are grateful for the leadership of the Biden Administration, U.S. Energy Secretary Jennifer Granholm, and various Congressional stakeholders—including Sens. Joe Manchin, Ted Cruz and John Cornyn. These export projects are expected to support efforts across the Indo-Pacific region to diversify energy supplies while transitioning away from coal in power production," said Justin Bird, CEO of Sempra Infrastructure. "They are also expected to help strengthen U.S. trading relationships, as well as create new jobs and boost the U.S. and Mexico economies."
Under the permits granted by DOE, Vista Pacifico LNG is authorized to re-export up to 200 billion cubic feet per year (Bcf/yr) of LNG from U.S.-sourced natural gas from the project under development in Topolobampo, Sinaloa, Mexico to any country with which the United States does not have an FTA requiring national treatment for trade in natural gas. Vista Pacifico LNG is projected to be a mid-scale facility with approximately 3.5 million tons per annum (Mtpa) of export capacity. Sempra Infrastructure is advancing the development of Vista Pacifico LNG in collaboration with Mexico's Federal Electricity Commission (CFE), as previously announced.
The DOE also increased the authorized export volumes of ECA LNG Phase 2, permitting it to re-export up to 636 Bcf/yr of LNG from U.S.-sourced natural gas from the proposed project in Ensenada, Baja California, Mexico to non-FTA nations. Both permits are applicable for the period beginning on the date of first commercial re-export through December 2050.
The proposed ECA LNG Phase 2 is expected to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. ECA LNG Phase 1 received non-FTA export authorization in 2019 and is currently under construction with commercial operations expected in 2025.
Development of ECA LNG Phase 2 and Vista Pacifico LNG is contingent upon completing the required commercial agreements, securing all necessary permits, obtaining financing, and reaching a final investment decision, among other factors.
bp looks to further developments at Tangguh with PSC extension
The Government of Indonesia has granted a 20-year extension of the Tangguh production sharing contract (Tangguh PSC) to bp, operator of the PSC, and its Tangguh PSC partners. Under the agreement, the Tangguh PSC, which consists of the Berau, Muturi and Wiriagar PSCs and was due to expire in 2035, will be extended to 2055.
The Tangguh PSC extension agreement was signed in Jakarta today by Arifin Tasrif, Indonesia’s Energy and Mineral Resources Minister, Dwi Soetjipto, Chairman of SKK Migas (Indonesia’s upstream oil & gas regulatory body), Kathy Wu, bp regional president, Asia Pacific gas & low carbon energy, and representatives of the Tangguh partners. The signing was witnessed by Anja-Isabel Dotzenrath, bp executive vice president, gas & low carbon energy.
Anja said: “This extension reflects bp’s long-term commitment to Indonesia. It will allow us to continue to build on the great work that our Indonesia team has been doing - with our partners and the strong support of the Government – to deliver much-needed natural gas safely and reliably from Tangguh to Indonesia and other markets. Today’s agreement will help open new possibilities for Tangguh’s future.”
“We would like to thank the Government of Indonesia, especially the Ministry of Energy and Mineral Resources and SKK Migas, for their continued support for this key project. We look forward to continuing to work with Indonesia and our partners for many years to come.”
Kathy Wu added: “With the extension, we will be able to continue our important work to meet the country's energy demand by expediting exploration activities, contributing to the state’s revenue and further supporting the local economy. With our recent addition of other blocks in Indonesia, this also reflects our confidence in the Government of Indonesia as we continue to invest in country
and deliver energy solutions.”
The Tangguh PSC extension agreement was signed in Jakarta today by Arifin Tasrif, Indonesia’s Energy and Mineral Resources Minister, Dwi Soetjipto, Chairman of SKK Migas (Indonesia’s upstream oil & gas regulatory body), Kathy Wu, bp regional president, Asia Pacific gas & low carbon energy, and representatives of the Tangguh partners. The signing was witnessed by Anja-Isabel Dotzenrath, bp executive vice president, gas & low carbon energy.
Anja said: “This extension reflects bp’s long-term commitment to Indonesia. It will allow us to continue to build on the great work that our Indonesia team has been doing - with our partners and the strong support of the Government – to deliver much-needed natural gas safely and reliably from Tangguh to Indonesia and other markets. Today’s agreement will help open new possibilities for Tangguh’s future.”
“We would like to thank the Government of Indonesia, especially the Ministry of Energy and Mineral Resources and SKK Migas, for their continued support for this key project. We look forward to continuing to work with Indonesia and our partners for many years to come.”
Kathy Wu added: “With the extension, we will be able to continue our important work to meet the country's energy demand by expediting exploration activities, contributing to the state’s revenue and further supporting the local economy. With our recent addition of other blocks in Indonesia, this also reflects our confidence in the Government of Indonesia as we continue to invest in country
and deliver energy solutions.”
Tuesday 20 December 2022
Production starts at Tinrhert Field Development project in Algeria
SONATRACH announces the completion, end of November, of the production start-up of Tinrhert gas field towards the existing units in Ohanet, Wilaya of Illizi, whose gradual production started in July 2022.
This project involves the construction of a collection network allowing to connect 36 gas wells from the Tinrhert field to the separation and compression facilities located in the nearby Ohanet field.
As a reminder, this development program was entrusted, in January 2019, to the National Company ENGCB, SONATRACH’s subsidiary, for its collection and connection part and to Petrofac Int. LLC for the construction of separation and compression facilities.
The commissioning completion of the surface facilities from Tinrhert gas fields to Ohanet has led to a production level of 4.5 million m3 /day of gas, 500 tons/day of LPG and 800 tons/day of condensate, thus exceeding the expected forecasts for this project.
Johan Sverdrup Phase 2 on stream
Aker BP is pleased to report that production from Johan Sverdrup Phase 2 started today. Johan Sverdrup is operated by Equinor, and Aker BP has 31.6 percent working interest. Phase 2 increases Johan Sverdrup’s plateau production capacity from 535,000 to 720,000 barrels per day gross, and the operator is aiming to increase this to 755,000 barrels per day.
The Johan Sverdrup Phase 2 project consists of a new platform, five new subsea systems, 28 new wells, a new module for the existing riser platform, and facilities to send power from shore to the Utsira High area. The project was delivered on time and cost, despite the Covid-19 pandemic.
– We are very pleased with the work that the operator Equinor and the contractors have done on behalf of the partnership in developing this field. Delivering Phase 2 safely, on time and cost is yet another confirmation of the excellent performance, says Aker BP’s CEO Karl Johnny Hersvik.
– The start-up of production from Phase 2 implies a substantial increase in the value creation from Johan Sverdrup for Aker BP and the other partners, as well as for the Norwegian society, Hersvik adds.
The Johan Sverdrup field receives power from shore through cables from Haugsneset north of Stavanger. The first cable currently supplies the first four platforms on the Johan Sverdrup field with electricity. The new cable supplies the fifth platform and the rest of the Utsira High installations, including Aker BP-operated Edvard Grieg and Ivar Aasen.
– With the electrification of Edvard Grieg and Ivar Aasen now completed, Aker BP has taken a new significant step towards our target of net zero emissions by 2030. This also consolidates our position as an industry leader when it comes to low CO2 emissions, says Hersvik.
The Johan Sverdrup Phase 2 project consists of a new platform, five new subsea systems, 28 new wells, a new module for the existing riser platform, and facilities to send power from shore to the Utsira High area. The project was delivered on time and cost, despite the Covid-19 pandemic.
– We are very pleased with the work that the operator Equinor and the contractors have done on behalf of the partnership in developing this field. Delivering Phase 2 safely, on time and cost is yet another confirmation of the excellent performance, says Aker BP’s CEO Karl Johnny Hersvik.
– The start-up of production from Phase 2 implies a substantial increase in the value creation from Johan Sverdrup for Aker BP and the other partners, as well as for the Norwegian society, Hersvik adds.
The Johan Sverdrup field receives power from shore through cables from Haugsneset north of Stavanger. The first cable currently supplies the first four platforms on the Johan Sverdrup field with electricity. The new cable supplies the fifth platform and the rest of the Utsira High installations, including Aker BP-operated Edvard Grieg and Ivar Aasen.
– With the electrification of Edvard Grieg and Ivar Aasen now completed, Aker BP has taken a new significant step towards our target of net zero emissions by 2030. This also consolidates our position as an industry leader when it comes to low CO2 emissions, says Hersvik.
Tuesday 13 December 2022
More gas to Hammerfest LNG: Askeladd on stream
Phase 1 of Askeladd will bring 18 billion cubic metres of gas and two million cubic metres of condensate to the market via the Hammerfest LNG plant on Melkøya.
Askeladd is a satellite field of the Snøhvit Field and developed as a subsea tie-in to the Snøhvit facility and Hammerfest LNG.
"Askeladd is now producing, the gas will help extend plateau production from Hammerfest LNG on Melkøya up tothree years," says Thor Johan Haave, Equinor’s vice president operations & maintenance, Hammerfest LNG.
During normal production, Hammerfest LNG (HLNG) delivers 18.4 million standard cubic metres of gas per day, or 6.5 billion cubic metres per year. This corresponds to the needs of around 6.5 million European households, or 5% of all Norwegian gas exports.
"HLNG delivers significant volumes to customers in Europe, and the gas from the Barents Sea reinforces our position as a predictable and reliable gas supplier. Askeladd and other projects in the region will ensure further value creation and production from HLNG for decades,” Haave adds.
The project was originally completed in 2020, but start-up had to wait until the Melkøya plant resumed operations after the fire the same year. The development was delivered on schedule and NOK 650 million below the cost estimate of NOK 5.2 billion.
"Just over 1.5 million person-hours of work have gone into the project, most of them performed by our suppliers. During the project period, Askeladd generated 250–300 person-years of work in Northern Norway, mainly in Hammerfest. In addition, many employees and suppliers have helped restart Hammerfest LNG, which makes it possible to phase in both Askeladd and future projects," says Trond Bokn, Equinor's senior vice president for project development.
Askeladd is the first of several projects in the further development of the Snøhvit field and the infrastructure around HLNG. Next up is Askeladd West with two new wells tied back to existing infrastructure, before further development continues with onshore compression and electrification through the Snøhvit Future project.
Askeladd is a satellite field of the Snøhvit Field and developed as a subsea tie-in to the Snøhvit facility and Hammerfest LNG.
"Askeladd is now producing, the gas will help extend plateau production from Hammerfest LNG on Melkøya up tothree years," says Thor Johan Haave, Equinor’s vice president operations & maintenance, Hammerfest LNG.
During normal production, Hammerfest LNG (HLNG) delivers 18.4 million standard cubic metres of gas per day, or 6.5 billion cubic metres per year. This corresponds to the needs of around 6.5 million European households, or 5% of all Norwegian gas exports.
"HLNG delivers significant volumes to customers in Europe, and the gas from the Barents Sea reinforces our position as a predictable and reliable gas supplier. Askeladd and other projects in the region will ensure further value creation and production from HLNG for decades,” Haave adds.
The project was originally completed in 2020, but start-up had to wait until the Melkøya plant resumed operations after the fire the same year. The development was delivered on schedule and NOK 650 million below the cost estimate of NOK 5.2 billion.
"Just over 1.5 million person-hours of work have gone into the project, most of them performed by our suppliers. During the project period, Askeladd generated 250–300 person-years of work in Northern Norway, mainly in Hammerfest. In addition, many employees and suppliers have helped restart Hammerfest LNG, which makes it possible to phase in both Askeladd and future projects," says Trond Bokn, Equinor's senior vice president for project development.
Askeladd is the first of several projects in the further development of the Snøhvit field and the infrastructure around HLNG. Next up is Askeladd West with two new wells tied back to existing infrastructure, before further development continues with onshore compression and electrification through the Snøhvit Future project.
Aker BP’s board approves field development projects
Aker BP’s board has approved that the operator Aker BP will vote in favour of submitting Plans for Development and Operation (PDO) for the NOAKA field development project, the Valhall PWP-Fenris project, the Skarv Satellite Project and the Utsira High projects.
The final approvals to submit the PDOs are expected to take place in the respective licences during the first half of December, after which the PDOs will be submitted to Norwegian authorities.
Net to Aker BP, the oil and gas resources in the projects are estimated to approximately 730 million barrels of oil equivalent, in line with the company’s July strategy update when adjusting for the previously announced postponement of the Wisting project.
Aker BP’s share of the investments in the projects are estimated to approximately USD 19 billion (nominal) in the period 2023-2028, and the corresponding average break-even oil price is estimated to USD 35-40 per barrel (calculated with 10 percent discount rate and accounting for the announced changes to the Norwegian Petroleum Tax adding on average USD 5-6/bbl to the break-even of the projects).
The final approvals to submit the PDOs are expected to take place in the respective licences during the first half of December, after which the PDOs will be submitted to Norwegian authorities.
Net to Aker BP, the oil and gas resources in the projects are estimated to approximately 730 million barrels of oil equivalent, in line with the company’s July strategy update when adjusting for the previously announced postponement of the Wisting project.
Aker BP’s share of the investments in the projects are estimated to approximately USD 19 billion (nominal) in the period 2023-2028, and the corresponding average break-even oil price is estimated to USD 35-40 per barrel (calculated with 10 percent discount rate and accounting for the announced changes to the Norwegian Petroleum Tax adding on average USD 5-6/bbl to the break-even of the projects).
Saturday 26 November 2022
Qatarenergy announces hydrocarbon discovery in Brazil’s Sépia field
QatarEnergy announced an oil discovery in the 4-BRSA-1386D-RJS well in Brazil’s world class Sépia oil field, which is located in the prolific Santos Basin in water depths of about 2,000 meters off the coast of Rio de Janeiro.
QatarEnergy acquired a working interest in the Sépia Co-Participated Area in December 2021 during the 2nd Transfer-of-Rights Surplus Bidding Round, which was organized and managed by Brazil’s National Agency for Petroleum, Natural Gas and Biofuels (ANP). The Area is operated by Petrobras (with a participating interest of about 52%) in partnership with TotalEnergies (19.2%), QatarEnergy (14.4%) and Petronas Petróleo Brasil Ltda (14.4%), with Pre Sal Petróleo S.A. (PPSA) as manager. The Sepia shared reservoir is currently producing about 170,000 barrels of oil per day.
Commenting on this occasion, His Excellency Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, said: “We are encouraged by this discovery, which comes as a result of strategic cooperation with reputable partners in our effort to unlock more global energy resources as part of our comprehensive growth strategy. On this occasion, I would like to congratulate our partners, and l look forward to more future achievements.”
The discovery is significant in that the well penetrated a net oil column, which is one of the thickest ever encountered in Brazil. Partners will continue operations to characterize the conditions of the discovered reservoirs and verify the extent of the discovery by conducting well tests.
QatarEnergy acquired a working interest in the Sépia Co-Participated Area in December 2021 during the 2nd Transfer-of-Rights Surplus Bidding Round, which was organized and managed by Brazil’s National Agency for Petroleum, Natural Gas and Biofuels (ANP). The Area is operated by Petrobras (with a participating interest of about 52%) in partnership with TotalEnergies (19.2%), QatarEnergy (14.4%) and Petronas Petróleo Brasil Ltda (14.4%), with Pre Sal Petróleo S.A. (PPSA) as manager. The Sepia shared reservoir is currently producing about 170,000 barrels of oil per day.
Commenting on this occasion, His Excellency Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, said: “We are encouraged by this discovery, which comes as a result of strategic cooperation with reputable partners in our effort to unlock more global energy resources as part of our comprehensive growth strategy. On this occasion, I would like to congratulate our partners, and l look forward to more future achievements.”
The discovery is significant in that the well penetrated a net oil column, which is one of the thickest ever encountered in Brazil. Partners will continue operations to characterize the conditions of the discovered reservoirs and verify the extent of the discovery by conducting well tests.
Saturday 19 November 2022
Subsea7 awarded contract offshore Trinidad and Tobago
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) announced today the award of a contract to Subsea Integration Alliance to support the development of bp’s Cypre project, a gas development located offshore Trinidad and Tobago. Subsea7’s scope of the awarded Subsea Integration Alliance contract is substantial2.
Subsea7’s scope covers the concept and design, engineering, procurement, construction and installation of a two-phase liquid natural gas tieback to the Juniper platform through dual flexible flowlines and a manifold gathering system, along with topside upgrades.
Design, engineering, and project management will commence immediately at Subsea7’s offices in the USA, with offshore installation planned for 2024.
Craig Broussard, Vice President for Subsea7 US, said: “We have been working closely with bp and our suppliers at the earliest possible stage to help develop and deliver an integrated SPS and SURF solution that optimises cost and efficiency, to accelerate first gas.”
Olivier Blaringhem, CEO for Subsea Integration Alliance said: ”bp’s Cypre project is a prime example of our ability to harness the key strengths of Subsea Integration Alliance; Subsea7 with its expertise in executing complex EPCI projects, and OneSubsea’s fast-track distribution of subsea production systems. Combined, we are delivering a refined solution which enables early first gas.”
Monday 14 November 2022
First power from Hywind Tampen
Power production from the first turbine in the floating wind farm Hywind Tampen in the North Sea started at 12:55 CET on 13 November. The power was delivered to the Gullfaks A platform in the North Sea.
“I am proud that we have now started production at Hywind Tampen, Norway’s first and the world’s largest floating wind farm. This is a unique project, the first wind farm in the world powering producing oil and gas installations,” says Geir Tungesvik, Equinor’s executive vice president for Projects, Drilling and Procurement.
Owned by the Gullfaks and Snorre partners, the Hywind Tampen wind farm is expected to meet about 35 percent of the electricity demand of the two fields. This will cut CO2 emissions from the fields by about 200,000 tonnes per year.
“The Norwegian content of the project is about 60 percent. This shows that we, together with our partners and suppliers, are building a new industry on the shoulders of the oil and gas business utilizing the competencies we together have acquired over many decades,” says Tungesvik.
Seven of eleven turbines are scheduled to come on stream during the year. The last four turbines have been assembled this autumn and will be installed on the field during a weather window next year. Even with just seven turbines on stream Hywind Tampen will be the world’s largest floating wind farm with a capacity of 60 MW.
Kjetil Hove, Equinor’s executive vice president for Exploration and Production Norway.
(Photo: Arne Reidar Mortensen / Equinor ASA)
With its world-class wind resources, the North Sea will continue to play a key role also in the energy transition and for the energy security of Europe and Norway. Hywind Tampen represents a first step towards developing a new industry within offshore wind in Norway, contributing to reliable, affordable, and sustainable energy supplies.
“Hywind Tampen cuts emissions from the oil and gas industry and increases the gas export to Europe. This is an important contribution towards transforming the Norwegian continental shelf from an oil and gas province to a broad energy province. Just a few years ago, no one would have believed that offshore platforms could be powered by electricity from floating wind turbines. Well, now we have started,” says Kjetil Hove, Equinor’s executive vice president for Exploration and Production Norway.
Facts about Hywind Tampen
“I am proud that we have now started production at Hywind Tampen, Norway’s first and the world’s largest floating wind farm. This is a unique project, the first wind farm in the world powering producing oil and gas installations,” says Geir Tungesvik, Equinor’s executive vice president for Projects, Drilling and Procurement.
Owned by the Gullfaks and Snorre partners, the Hywind Tampen wind farm is expected to meet about 35 percent of the electricity demand of the two fields. This will cut CO2 emissions from the fields by about 200,000 tonnes per year.
“The Norwegian content of the project is about 60 percent. This shows that we, together with our partners and suppliers, are building a new industry on the shoulders of the oil and gas business utilizing the competencies we together have acquired over many decades,” says Tungesvik.
Seven of eleven turbines are scheduled to come on stream during the year. The last four turbines have been assembled this autumn and will be installed on the field during a weather window next year. Even with just seven turbines on stream Hywind Tampen will be the world’s largest floating wind farm with a capacity of 60 MW.
Kjetil Hove, Equinor’s executive vice president for Exploration and Production Norway.
(Photo: Arne Reidar Mortensen / Equinor ASA)
With its world-class wind resources, the North Sea will continue to play a key role also in the energy transition and for the energy security of Europe and Norway. Hywind Tampen represents a first step towards developing a new industry within offshore wind in Norway, contributing to reliable, affordable, and sustainable energy supplies.
“Hywind Tampen cuts emissions from the oil and gas industry and increases the gas export to Europe. This is an important contribution towards transforming the Norwegian continental shelf from an oil and gas province to a broad energy province. Just a few years ago, no one would have believed that offshore platforms could be powered by electricity from floating wind turbines. Well, now we have started,” says Kjetil Hove, Equinor’s executive vice president for Exploration and Production Norway.
Facts about Hywind Tampen
- Partners: Equinor, Petoro, OMV, Vår Energi, Wintershall Dea and INPEX Idemitsu
- Hywind Tampen has a system capacity of 88 MW
- The wind farm is located some 140 kilometres from shore
- Water depth: between 260 and 300 metres
- The turbines are installed on a floating concrete structure with a joint mooring system
- Enova and the Business Sector’s NoX Fund have supported the project by NOK 2.3 billion and NOK 566 million respectively to stimulate technology development within offshore wind and emission reductions
Saturday 5 November 2022
Peregrino phase 2 on stream
On 10 October at 20:00 local time, the new platform in Brazil, Peregrino C, produced its very first oil.
Peregrino phase 2 will extend the Peregrino field life to 2040. Phase 2 adds 250-300 million barrels of oil, while at the same time halving expected CO2 emissions per barrel over the field remaining lifetime.
“I am thrilled that we have started production from the new Peregrino C platform. Covid-19 has made Peregrino phase 2 a challenging project, and I want to thank everyone involved for delivering the project with excellent HSE results,” says Geir Tungesvik, Equinor’s executive vice president for Projects, Drilling & Procurement.
Peregrino phase 2 consists of a new platform with drilling facilities and living quarters tied in to the existing Peregrino FPSO, as well as a new pipeline importing gas to the platform for power generation.
In operation the new platform will provide 350 long-term jobs offshore and onshore in Brazil.
The project was on schedule for planned start-up late in 2020 when Covid-19 hit the project hard, leading to cuts in the workforce several times in the crucial and normally labor-intensive hook-up phase. Still, Peregrino phase 2 is delivered within the original USD 3 billion cost estimate.
In line with Equinor’s low carbon strategy, measures have been taken to reduce CO2 emissions from the Peregrino field. By switching from diesel to gas for power generation on Peregrino C, phase 2 will avoid 100,000 tonnes of CO2 emissions from the Peregrino field per year.
This will also reduce costs and simplify logistics in the operational phase.
“The start-up of Peregrino Phase 2 is an important milestone in Equinor’s growth strategy in Brazil. This project showcases how we can bring valuable new resources onto production at the same time as investing in technology to cut carbon emissions. I am proud that Peregrino Phase 2 will increase field production to 110,000 barrels per day at plateau whilst halving our emissions intensity,” says Al Cook, Equinor’s executive vice president for Exploration & Production International.
The new platform is also equipped with the latest digital tools, like a 3D model of the entire platform that operators can use on an iPad in the field. This improves cooperation offshore and between the platform and the onshore operational support team in Rio de Janeiro.
New digital solutions will also contribute to optimized production, reducing energy usage and thereby CO2 emissions.
Facts
- Located in the Campos Basin, the Peregrino field started production in 2011.
- Equinor is the operator (60%), with Sinochem (40%) as partner in the field.
- Peregrino Phase 1 consists of a floating production vessel (FPSO) supported by two wellhead platforms: Peregrino A and Peregrino B.
- Peregrino is the largest field operated by Equinor outside Norway and the first of a series of major field developments in Brazil.
- The Peregrino field has so far produced more than 210 million barrels of oil since the field came on stream in 2011.
Maximising economic recovery in the UK’s Southern North Sea for Shell and Hartshead Resources Sea for Shell and Hartshead Resources
Petrofac, a leading provider of services to the global energy industry, has been selected by Hartshead Resources to conduct an engineering study to define its Phase I offtake route from their Somerville and Anning gas fields.
The study aims to define an efficient and fast route to increase the UK’s energy security by making the most of Shell’s existing infrastructure in the Southern North Sea. It will provide a basis for the design and cost estimate, and the brownfield modifications needed, to tie-in Hartshead’s proposed new facilities to Shell’s Corvette and Leman A platforms. From there the gas will be transported to Bacton for onshore processing and delivery to the UK’s transmission system.
Hartshead plans to take a Final Investment Decision (FID) on the development, including new platforms, in 2023 and aims to achieve first gas in late 2024.
Nick Shorten, Chief Operating Officer for Petrofac’s Asset Solutions business said:
“It’s great to see Petrofac’s considerable engineering expertise helping to maximise economic recovery. Using Shell’s existing infrastructure to tap into Hartshead’s gas fields will efficiently help support the UK’s energy security at this critical time.”
The scope of Petrofac’s study includes offshore construction support for the subsea pipeline tie-in activities on the Corvette to Leman Alpha export pipeline, communication connections, pipework for system control and export route options and control room integration.
The study aims to define an efficient and fast route to increase the UK’s energy security by making the most of Shell’s existing infrastructure in the Southern North Sea. It will provide a basis for the design and cost estimate, and the brownfield modifications needed, to tie-in Hartshead’s proposed new facilities to Shell’s Corvette and Leman A platforms. From there the gas will be transported to Bacton for onshore processing and delivery to the UK’s transmission system.
Hartshead plans to take a Final Investment Decision (FID) on the development, including new platforms, in 2023 and aims to achieve first gas in late 2024.
Nick Shorten, Chief Operating Officer for Petrofac’s Asset Solutions business said:
“It’s great to see Petrofac’s considerable engineering expertise helping to maximise economic recovery. Using Shell’s existing infrastructure to tap into Hartshead’s gas fields will efficiently help support the UK’s energy security at this critical time.”
The scope of Petrofac’s study includes offshore construction support for the subsea pipeline tie-in activities on the Corvette to Leman Alpha export pipeline, communication connections, pipework for system control and export route options and control room integration.
Sunday 25 September 2022
TechnipFMC Awarded Significant Subsea Contract by TotalEnergies for Lapa North East Development
TechnipFMC (NYSE: FTI) has been awarded a significant(1) engineering, procurement, construction and installation (EPCI) contract by TotalEnergies for its Lapa North East field in the pre-salt Santos Basin offshore Brazil.
TechnipFMC will reconfigure and install umbilicals and flexible pipe in a new configuration that will further secure the production of the field.
Jonathan Landes, President, Subsea, at TechnipFMC, commented: “The Brazilian offshore market is becoming more diverse with regard to work scope and customer opportunity. On Lapa North East, we are working with a valued client with whom we have built a trusted relationship. By offering the flexibility of a phased campaign, we are helping TotalEnergies accelerate its schedule and begin production sooner.”
TechnipFMC will reconfigure and install umbilicals and flexible pipe in a new configuration that will further secure the production of the field.
Jonathan Landes, President, Subsea, at TechnipFMC, commented: “The Brazilian offshore market is becoming more diverse with regard to work scope and customer opportunity. On Lapa North East, we are working with a valued client with whom we have built a trusted relationship. By offering the flexibility of a phased campaign, we are helping TotalEnergies accelerate its schedule and begin production sooner.”
Saturday 24 September 2022
McDermott Selected for Begonia Project by TotalEnergies EP Angola Block
McDermott International has been awarded a significant contract by TotalEnergies EP Angola Block 17/06 for engineering, procurement, supply, construction, installation, pre-commissioning and assistance to commissioning and start-up (EPSCI) on its Begonia Project. The Begonia field is located offshore Angola in water depth between 400 to 750 meters.
The Begonia Project will collect hydrocarbons from a reservoir, via a subsea-to-subsea tie-back to the existing CLOV floating production, storage and offloading (FPSO) unit. McDermott will provide all EPSCI services for subsea umbilicals, water injection and production flowlines. There are three production wells in total which are gathered through a multiphase production flowline, approximately 12 miles (20 kilometres) in length. The two water injection wells are connected back to an existing riser.
McDermott will utilize its diversified fleet of specialty marine construction vessels: The North Ocean 102 will install the umbilicals, and the Amazon will install the rigid pipelines using its world-class J-lay pipeline system and advanced technology.
"This award leverages our extensive subsea and deepwater expertise and is testament to our customer's confidence in our newly converted, state-of-the-art Amazon vessel," said Mahesh Swaminathan, Senior Vice President, Subsea and Deepwater for McDermott. "The Begonia Project represents our first subsea project in Angola and supports our strategic focus to grow our footprint in Africa."
As part the company's commitment to long-term growth and investment in Angola, McDermott plans to maximize the use of local suppliers and subcontractors throughout the project and provide training to develop a local workforce.
Project management and engineering will be executed from McDermott's teams in London and Kuala Lumpur, Malaysia. The fabrication will be executed locally in Angola, West Africa.
The Begonia Project will collect hydrocarbons from a reservoir, via a subsea-to-subsea tie-back to the existing CLOV floating production, storage and offloading (FPSO) unit. McDermott will provide all EPSCI services for subsea umbilicals, water injection and production flowlines. There are three production wells in total which are gathered through a multiphase production flowline, approximately 12 miles (20 kilometres) in length. The two water injection wells are connected back to an existing riser.
McDermott will utilize its diversified fleet of specialty marine construction vessels: The North Ocean 102 will install the umbilicals, and the Amazon will install the rigid pipelines using its world-class J-lay pipeline system and advanced technology.
"This award leverages our extensive subsea and deepwater expertise and is testament to our customer's confidence in our newly converted, state-of-the-art Amazon vessel," said Mahesh Swaminathan, Senior Vice President, Subsea and Deepwater for McDermott. "The Begonia Project represents our first subsea project in Angola and supports our strategic focus to grow our footprint in Africa."
As part the company's commitment to long-term growth and investment in Angola, McDermott plans to maximize the use of local suppliers and subcontractors throughout the project and provide training to develop a local workforce.
Project management and engineering will be executed from McDermott's teams in London and Kuala Lumpur, Malaysia. The fabrication will be executed locally in Angola, West Africa.
Tuesday 20 September 2022
Well-Safe Protector to decommission Neptune Energy wells in North Sea
Well-Safe Solutions and Neptune Energy have agreed a contract for the Well-Safe Protector jack-up rig to plug and abandon (P&A) at least four subsea and 21 platform wells in the Dutch and UK sectors of the North Sea.
The one-year, firm contract also enables Neptune Energy to take up Well-Safe’s broad range of decommissioning engineering services if required, as well as the option of up to eight three-month extensions.
Mobilising during Q1 2023 in direct continuation from an earlier well decommissioning project for Ithaca Energy, the Well-Safe Protector is a harsh environment, independent leg cantilever design jack-up rig with an extensive operational history in the North Sea.
Duncan Morison, Rig Manager of the Well-Safe Protector, said: “With the addition of a further backlog of work to the Well-Safe Protector’s schedule, we are delighted at the level of interest the Well-Safe business model continues to generate in mature fields such as the North Sea.
“The Well-Safe Protector boasts a large volume of deck space for tubing, casing and conductor recovery, allowing effective batch operations and helping our clients to realise considerable operational savings.
“There are clear operational synergies between Well-Safe Solutions and Neptune Energy, and we look forward to collaborating with the Neptune team to effectively and efficiently plug and abandon these fields.”
Stuart Payne, NSTA Director of Supply Chain, Decommissioning and HR, added: “We have consistently pressed operators and the supply chain to work in a collaborative way to form well decommissioning campaigns, which are more cost-efficient and help save time and lower emissions.
“The Well-Safe Protector’s upcoming mobilisation for a multi-operator campaign is the latest encouraging sign that industry has got the message loud and clear. The cross-border element of this work also highlights the potential for exporting the considerable decommissioning expertise of the UK supply chain to other regions.”
The announcement follows on from news earlier in the summer that the Well-Safe Protector will plug and abandon six wells on the Anglia platform in the Southern North Sea for Ithaca Energy, mobilising in autumn 2022.
Decommissioning operations will be on D18a-A, G14-B, K12-S2, L10-S2 and K9c-A platforms in the Netherlands and the Neptune-operated Minke and Orca fields
The one-year, firm contract also enables Neptune Energy to take up Well-Safe’s broad range of decommissioning engineering services if required, as well as the option of up to eight three-month extensions.
Mobilising during Q1 2023 in direct continuation from an earlier well decommissioning project for Ithaca Energy, the Well-Safe Protector is a harsh environment, independent leg cantilever design jack-up rig with an extensive operational history in the North Sea.
Duncan Morison, Rig Manager of the Well-Safe Protector, said: “With the addition of a further backlog of work to the Well-Safe Protector’s schedule, we are delighted at the level of interest the Well-Safe business model continues to generate in mature fields such as the North Sea.
“The Well-Safe Protector boasts a large volume of deck space for tubing, casing and conductor recovery, allowing effective batch operations and helping our clients to realise considerable operational savings.
“There are clear operational synergies between Well-Safe Solutions and Neptune Energy, and we look forward to collaborating with the Neptune team to effectively and efficiently plug and abandon these fields.”
Stuart Payne, NSTA Director of Supply Chain, Decommissioning and HR, added: “We have consistently pressed operators and the supply chain to work in a collaborative way to form well decommissioning campaigns, which are more cost-efficient and help save time and lower emissions.
“The Well-Safe Protector’s upcoming mobilisation for a multi-operator campaign is the latest encouraging sign that industry has got the message loud and clear. The cross-border element of this work also highlights the potential for exporting the considerable decommissioning expertise of the UK supply chain to other regions.”
The announcement follows on from news earlier in the summer that the Well-Safe Protector will plug and abandon six wells on the Anglia platform in the Southern North Sea for Ithaca Energy, mobilising in autumn 2022.
Decommissioning operations will be on D18a-A, G14-B, K12-S2, L10-S2 and K9c-A platforms in the Netherlands and the Neptune-operated Minke and Orca fields
Wednesday 14 September 2022
Nova 1st oil: Wintershall Dea increases production volumes in Norway
Wintershall Dea has started production from the own-operated Nova oil field in the Norwegian North Sea together with the project partners Sval Energi and Pandion Energy Norge. It comes on stream at a time where Europe needs every additional barrel it can get. The completion of Nova emphasizes Wintershall Dea’s strength as one of the largest subsea operators on the Norwegian Continental Shelf.
“With the start-up of the major project Nova, Wintershall Dea is now operating three subsea production fields in Norway. We are expanding our subsea technology expertise and meanwhile three further tieback-developments, including Dvalin, are in the planning. As a subsea operator we are committed to making the most of the infrastructure that Norway has spent decades developing, as well as maintaining a low-carbon intensity portfolio while producing the energy that Europe needs,” said Hugo Dijkgraaf, Wintershall Dea Member of the Executive Board and Chief Technology Officer.
ADDING VALUE FOR NORWAY WITH LOW-EMISSIONS SOLUTIONS
This new field is a prime example for energy deliveries using existing infrastructure in the area: Nova is a tieback to the nearby Gjøa platform, which is sustainably electrified with renewable power from shore. The Neptune Energy-operated host platform will provide gas lift and water injection to the field and receives the Nova hydrocarbons. The tieback solution further extends the economic lifetime and increases the profitability of the Gjøa field, in which Wintershall Dea has a 28% share.
Nova Project director André Hesse said: “This is a big moment for Wintershall Dea and everyone involved. Thanks to the hard work of our project team, our suppliers, license partners and the host operator, we could overcome challenges by a strong and consistent team effort. A big thank you to everyone who made this happen!”
STRENGTHENING LOW-CARBON SUBSEA PRODUCTION AND INCREASING EUROPE’S ENERGY SUPPLY SECURITY
With Nova, Wintershall Dea is increasing Europe’s energy supply in a time of need. When the Dvalin field and the partner-operated Njord Future-project, in which Wintershall Dea holds a 50% share, come on stream as currently planned later this year, Wintershall Dea will provide significant further gas and oil volumes to Europe. In addition, the company operates recent discoveries like Dvalin North, planned for PDO hand-in (Plan for Development and Operations) by the end of 2022, and several other discoveries which could be developed in the future. For instance, Wintershall Dea is a partner in the Aker BP-operated Storjo discovery in the Norwegian Sea.
“By exploring for and developing new fields near existing infrastructure, we are not only delivering new barrels, we are also potentially extending the lifetime of surrounding assets. This secures the possibility for future tie-ins, and returns value to the partnership, suppliers, and the Norwegian society” said Michael Zechner, Managing Director at Wintershall Dea Norge.
Wintershall Dea, Europe’s leading independent gas and oil company, has ambitions to be net zero across its entire upstream operations by 2030, both operated and non-operated. This includes Scope 1 (direct) and Scope 2 (indirect) greenhouse gas emissions at equity share basis. As Gjøa is powered via hydropower from the Norwegian mainland, Nova will be a low carbon-intensity field and contribute to Wintershall Dea’s excellent emission reduction performance.
ABOUT NOVA
Nova is located in the Norwegian North Sea, about 120 kilometres northwest of Bergen and approximately 17 kilometres southwest of Gjøa. The water depth is roughly 370 metres. The Nova field consists of two subsea templates, one with three oil producers and one with three water injectors, tied back to the Gjøa platform.
The expected recoverable gross reserves from the field are estimated at 90 million barrels of oil equivalent (boe), of which the majority will be oil. This would be sufficient to cover Berlin’s oil demand for more than five years.1
Oil from Nova will be transported via Gjøa through the Troll Oil Pipeline II to Mongstad in Norway, associated gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK, supplying the European energy market.
Wintershall Dea is operator of the Nova field with a 45% share. Sval Energi also has a 45% share and Pandion Energy Norge owns 10%. Wintershall Dea has entered into an agreement to transfer a 6% share of the Nova field to OKEA. Completion is expected in Q4 2022 and Wintershall Dea’s share will then be lowered to 39%.
“With the start-up of the major project Nova, Wintershall Dea is now operating three subsea production fields in Norway. We are expanding our subsea technology expertise and meanwhile three further tieback-developments, including Dvalin, are in the planning. As a subsea operator we are committed to making the most of the infrastructure that Norway has spent decades developing, as well as maintaining a low-carbon intensity portfolio while producing the energy that Europe needs,” said Hugo Dijkgraaf, Wintershall Dea Member of the Executive Board and Chief Technology Officer.
ADDING VALUE FOR NORWAY WITH LOW-EMISSIONS SOLUTIONS
This new field is a prime example for energy deliveries using existing infrastructure in the area: Nova is a tieback to the nearby Gjøa platform, which is sustainably electrified with renewable power from shore. The Neptune Energy-operated host platform will provide gas lift and water injection to the field and receives the Nova hydrocarbons. The tieback solution further extends the economic lifetime and increases the profitability of the Gjøa field, in which Wintershall Dea has a 28% share.
Nova Project director André Hesse said: “This is a big moment for Wintershall Dea and everyone involved. Thanks to the hard work of our project team, our suppliers, license partners and the host operator, we could overcome challenges by a strong and consistent team effort. A big thank you to everyone who made this happen!”
STRENGTHENING LOW-CARBON SUBSEA PRODUCTION AND INCREASING EUROPE’S ENERGY SUPPLY SECURITY
With Nova, Wintershall Dea is increasing Europe’s energy supply in a time of need. When the Dvalin field and the partner-operated Njord Future-project, in which Wintershall Dea holds a 50% share, come on stream as currently planned later this year, Wintershall Dea will provide significant further gas and oil volumes to Europe. In addition, the company operates recent discoveries like Dvalin North, planned for PDO hand-in (Plan for Development and Operations) by the end of 2022, and several other discoveries which could be developed in the future. For instance, Wintershall Dea is a partner in the Aker BP-operated Storjo discovery in the Norwegian Sea.
“By exploring for and developing new fields near existing infrastructure, we are not only delivering new barrels, we are also potentially extending the lifetime of surrounding assets. This secures the possibility for future tie-ins, and returns value to the partnership, suppliers, and the Norwegian society” said Michael Zechner, Managing Director at Wintershall Dea Norge.
Wintershall Dea, Europe’s leading independent gas and oil company, has ambitions to be net zero across its entire upstream operations by 2030, both operated and non-operated. This includes Scope 1 (direct) and Scope 2 (indirect) greenhouse gas emissions at equity share basis. As Gjøa is powered via hydropower from the Norwegian mainland, Nova will be a low carbon-intensity field and contribute to Wintershall Dea’s excellent emission reduction performance.
ABOUT NOVA
Nova is located in the Norwegian North Sea, about 120 kilometres northwest of Bergen and approximately 17 kilometres southwest of Gjøa. The water depth is roughly 370 metres. The Nova field consists of two subsea templates, one with three oil producers and one with three water injectors, tied back to the Gjøa platform.
The expected recoverable gross reserves from the field are estimated at 90 million barrels of oil equivalent (boe), of which the majority will be oil. This would be sufficient to cover Berlin’s oil demand for more than five years.1
Oil from Nova will be transported via Gjøa through the Troll Oil Pipeline II to Mongstad in Norway, associated gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK, supplying the European energy market.
Wintershall Dea is operator of the Nova field with a 45% share. Sval Energi also has a 45% share and Pandion Energy Norge owns 10%. Wintershall Dea has entered into an agreement to transfer a 6% share of the Nova field to OKEA. Completion is expected in Q4 2022 and Wintershall Dea’s share will then be lowered to 39%.
Tuesday 6 September 2022
McDermott Completes Process Module Sail Away on Tyra Redevelopment Project
McDermott International has successfully completed the sail away of the Tyra East G (TEG) gas processing module on the Tyra Redevelopment Project for TotalEnergies and its Danish Underground Consortium partners Noreco and Nordsøfonden.
The module weighs approximately 18,700 tons (17,000 metric tons) and set sail on September 1 from McDermott's facility in Batam, Indonesia. This important milestone is the culmination of more than 18.8 million work hours of engineering and constructing the process module.
"This is an incredible milestone on a large-scale and complex project. As an engineering, procurement, construction, and commissioning contractor for the Tyra Redevelopment, we leveraged synergies throughout the lifecycle of the project while maintaining a high focus on safety," said Tareq Kawash, Senior Vice President, Onshore of McDermott. "We are proud that our work contributes to TotalEnergies' vision and pursuit of sustainable North Sea operations."
The TEG module will be a crucial part of Tyra II; the new high-tech hub for Denmark's natural gas production and will reduce CO2 emissions by 30 percent.
"The sail away of the process module is of key importance for the Tyra Redevelopment Project as it marks the conclusion of onshore construction, and with this all the remaining work on Tyra II will take place in the Danish North Sea. The sheer size and magnitude of the process module is just incredible, and it will be fabulous to unite this final major component with the remaining platforms at the Tyra field in the next month," said Eric Delattre, Managing Director for TotalEnergies Exploration & Production Denmark.
The Tyra Redevelopment project represents the largest ever oil and gas investment in the Danish North Sea. Once the redeveloped Tyra II is back on stream, it is expected to deliver 2.8 billion cubic meters of gas per year which amounts to 80 percent of the forecasted Danish gas production. Tyra II will secure continued production of natural gas with 30 percent less CO2 emissions, significantly contributing to Denmark's energy security by reducing Denmark and the EU's dependency on Russian gas. The new facilities will be located approximately 139 miles (225 kilometers) west of Denmark in the North Sea.
The module weighs approximately 18,700 tons (17,000 metric tons) and set sail on September 1 from McDermott's facility in Batam, Indonesia. This important milestone is the culmination of more than 18.8 million work hours of engineering and constructing the process module.
"This is an incredible milestone on a large-scale and complex project. As an engineering, procurement, construction, and commissioning contractor for the Tyra Redevelopment, we leveraged synergies throughout the lifecycle of the project while maintaining a high focus on safety," said Tareq Kawash, Senior Vice President, Onshore of McDermott. "We are proud that our work contributes to TotalEnergies' vision and pursuit of sustainable North Sea operations."
The TEG module will be a crucial part of Tyra II; the new high-tech hub for Denmark's natural gas production and will reduce CO2 emissions by 30 percent.
"The sail away of the process module is of key importance for the Tyra Redevelopment Project as it marks the conclusion of onshore construction, and with this all the remaining work on Tyra II will take place in the Danish North Sea. The sheer size and magnitude of the process module is just incredible, and it will be fabulous to unite this final major component with the remaining platforms at the Tyra field in the next month," said Eric Delattre, Managing Director for TotalEnergies Exploration & Production Denmark.
The Tyra Redevelopment project represents the largest ever oil and gas investment in the Danish North Sea. Once the redeveloped Tyra II is back on stream, it is expected to deliver 2.8 billion cubic meters of gas per year which amounts to 80 percent of the forecasted Danish gas production. Tyra II will secure continued production of natural gas with 30 percent less CO2 emissions, significantly contributing to Denmark's energy security by reducing Denmark and the EU's dependency on Russian gas. The new facilities will be located approximately 139 miles (225 kilometers) west of Denmark in the North Sea.
Friday 19 August 2022
Subsea 7 awarded contract offshore Norway
Subsea 7 today announced the award of a sizeable1 contract by Aker BP for the Trell & Trine field development, located in the Alvheim area of the North Sea.
The project involves a subsea tie-back of approximately 21 kilometers to the Alvheim FPSO, via the existing East Kameleon subsea manifold. The contract scope includes engineering, procurement, construction and installation (EPCI) of the pipelines, spools, protection covers and tie-ins using key vessels from Subsea 7’s fleet. The production pipeline is a pipe-in-pipe design.
Project management and engineering will commence immediately at Subsea 7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea 7’s spoolbase at Vigra, Norway and offshore operations are expected to take place in 2023 and 2024.
Monica Th. Bjørkmann, Vice President for Subsea 7 Norway said: “This award is a continuation of Aker BP’s exciting development of the Alvheim area. The Trell & Trine field development is an excellent example of how our collaboration with Aker BP and Aker Solutions, through the Aker BP Subsea Alliance2, builds upon our collective experience from previous and ongoing projects. The partnership enables Subsea 7 to engage early in the field development process, optimising design solutions and contributing to a positive final investment decision. Subsea 7 is looking forward to continuing our collaboration for the Trell & Trine field development, with a focus on safe, efficient and reliable operations.”
The project involves a subsea tie-back of approximately 21 kilometers to the Alvheim FPSO, via the existing East Kameleon subsea manifold. The contract scope includes engineering, procurement, construction and installation (EPCI) of the pipelines, spools, protection covers and tie-ins using key vessels from Subsea 7’s fleet. The production pipeline is a pipe-in-pipe design.
Project management and engineering will commence immediately at Subsea 7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea 7’s spoolbase at Vigra, Norway and offshore operations are expected to take place in 2023 and 2024.
Monica Th. Bjørkmann, Vice President for Subsea 7 Norway said: “This award is a continuation of Aker BP’s exciting development of the Alvheim area. The Trell & Trine field development is an excellent example of how our collaboration with Aker BP and Aker Solutions, through the Aker BP Subsea Alliance2, builds upon our collective experience from previous and ongoing projects. The partnership enables Subsea 7 to engage early in the field development process, optimising design solutions and contributing to a positive final investment decision. Subsea 7 is looking forward to continuing our collaboration for the Trell & Trine field development, with a focus on safe, efficient and reliable operations.”
Wednesday 17 August 2022
Santos announces Pikka FID
Santos, as operator of the Pikka Unit joint venture, today announced a final investment decision (FID) has been taken to proceed with the US$2.6 billion gross (US$1.3 billion Santos-share) Pikka Phase 1 oil project located on the North Slope of Alaska.
Pikka Phase 1 is expected to produce 80,000 barrels a day of oil gross with first oil anticipated in 2026.
The project has strong fundamentals, is located in a world-class oil producing province with significant existing infrastructure, has low unabated emissions intensity and is supported by key stakeholders, including the State of Alaska, the North Slope Borough, the landowner company Kuukpik Corporation and the Arctic Slope Regional Corporation (ASRC).
Taking FID on Pikka Phase 1 is consistent with Santos’ goal of achieving net-zero (scope 1 and 2, equity share) by 2040. Santos is committed to delivering a net-zero project (scope 1 and 2, equity share) and has entered into Memorandums of Understanding with Alaska Native Corporations to deliver carbon offset projects, including a Strategic Alliance with ASRC Energy Services, a wholly-owned subsidiary of ASRC, on leading technology development for carbon solutions in the Arctic.
Alaska has a rich and proud oil and gas history – welcoming the jobs, investment and community development the industry provides. Pikka Phase 1 represents one of the lowest-cost and lowest unabated emissions intensity new oil projects in the region.
Santos is focussed on local procurement and local employment as part of the project, with 98 per cent of current employees living in Alaska. Phase 1 of the project is expected to create more than 500 jobs and construction of the project will deliver approximately 2,600 jobs.
The Pikka Phase 1 project represents compelling value for Santos shareholders given its robust economics and strong local stakeholder support.
Santos Managing Director and Chief Executive Officer Kevin Gallagher said Pikka Phase 1 is the right project at the right time in the right location.
“Global oil and gas markets are seeing increased volatility and countries are looking to diversify their supply sources away from Russia, which according to the International Energy Agency, currently produces 18 per cent of the world’s gas and 12 per cent of its oil,” Mr Gallagher said.
“Low-carbon oil projects like Pikka Phase 1 respond to new demand for OECD supply and are critical for global and United States energy security, that has been highlighted since the Russian invasion of Ukraine.
“Santos has emission reduction plans to achieve scope 1 and 2 net-zero emissions by 2040 and in-line with that commitment, Pikka will be a net-zero project.
“The project will add further diversification to our portfolio and reduces geographic concentration risk.
“Pikka Phase 1 will execute a responsible development plan with a small surface footprint and utilise existing infrastructure, including the Kuparuk transportation pipeline and the Trans-Alaska pipeline system.
“We have a world-class team with a rich history of successfully carrying out work on the North Slope. With approximately 90 per cent of project spend within North America minimising supply chain risk and civils work already completed, the project is well positioned for execution.”
Santos has a 51% interest in the Pikka Unit. The remaining interest is held by Repsol.
Pikka Phase 1 is expected to produce 80,000 barrels a day of oil gross with first oil anticipated in 2026.
The project has strong fundamentals, is located in a world-class oil producing province with significant existing infrastructure, has low unabated emissions intensity and is supported by key stakeholders, including the State of Alaska, the North Slope Borough, the landowner company Kuukpik Corporation and the Arctic Slope Regional Corporation (ASRC).
Taking FID on Pikka Phase 1 is consistent with Santos’ goal of achieving net-zero (scope 1 and 2, equity share) by 2040. Santos is committed to delivering a net-zero project (scope 1 and 2, equity share) and has entered into Memorandums of Understanding with Alaska Native Corporations to deliver carbon offset projects, including a Strategic Alliance with ASRC Energy Services, a wholly-owned subsidiary of ASRC, on leading technology development for carbon solutions in the Arctic.
Alaska has a rich and proud oil and gas history – welcoming the jobs, investment and community development the industry provides. Pikka Phase 1 represents one of the lowest-cost and lowest unabated emissions intensity new oil projects in the region.
Santos is focussed on local procurement and local employment as part of the project, with 98 per cent of current employees living in Alaska. Phase 1 of the project is expected to create more than 500 jobs and construction of the project will deliver approximately 2,600 jobs.
The Pikka Phase 1 project represents compelling value for Santos shareholders given its robust economics and strong local stakeholder support.
Santos Managing Director and Chief Executive Officer Kevin Gallagher said Pikka Phase 1 is the right project at the right time in the right location.
“Global oil and gas markets are seeing increased volatility and countries are looking to diversify their supply sources away from Russia, which according to the International Energy Agency, currently produces 18 per cent of the world’s gas and 12 per cent of its oil,” Mr Gallagher said.
“Low-carbon oil projects like Pikka Phase 1 respond to new demand for OECD supply and are critical for global and United States energy security, that has been highlighted since the Russian invasion of Ukraine.
“Santos has emission reduction plans to achieve scope 1 and 2 net-zero emissions by 2040 and in-line with that commitment, Pikka will be a net-zero project.
“The project will add further diversification to our portfolio and reduces geographic concentration risk.
“Pikka Phase 1 will execute a responsible development plan with a small surface footprint and utilise existing infrastructure, including the Kuparuk transportation pipeline and the Trans-Alaska pipeline system.
“We have a world-class team with a rich history of successfully carrying out work on the North Slope. With approximately 90 per cent of project spend within North America minimising supply chain risk and civils work already completed, the project is well positioned for execution.”
Santos has a 51% interest in the Pikka Unit. The remaining interest is held by Repsol.
Monday 8 August 2022
Angola: TotalEnergies is Rolling out its Multi-Energy Strategy by Launching Three Projects in Oil, Gas and Solar Energy
As part of the rollout of its multi-energy strategy in Angola, TotalEnergies announces the launch of the Begonia oil field, and Quiluma and Maboqueiro gas fields developments, as well as its first photovoltaic project in the country, with a capacity of 35 MWp and the possibility of adding 45 MWp in a second phase.
Begonia, the first development on Block 17/06
TotalEnergies today announces the final investment decision for Begonia, the first development of block 17/06, located 150 kilometers off the Angolan coast, in agreement with concession holder Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG) and its partners on Block 17/06.
The Begonia development consists of five wells tied back to the Pazflor FPSO (floating production, storage and offloading unit), already in operation on Block 17. After commissioning, expected in late 2024, it will add 30,000 barrels a day to the FPSO's production.
After CLOV Phase 3, another satellite project that produces 30,000 barrels a day and was launched on Block 17 in June 2022, Begonia is the second TotalEnergies-operated project in Angola to use a standardized subsea production system, saving up to 20% on costs and shortening lead times for equipment delivery.
The project represents an investment of $850 million and 1.3 million man-hours of work, 70% of which will be carried out in Angola.
Quiluma and Maboqueiro, Angola's first non-associated natural gas projects
TotalEnergies also announces the final investment decision for the “Non Associated Gas 1” (NAG1) project, in which the Company holds an 11.8% interest alongside its partners, Eni (operator with 25.6%), Chevron (31%), Sonangol P&P (19.8%) and bp (11.8%).
NAG1 is the first non-associated natural gas project developed in Angola. Gas produced from the Quiluma and Maboqueiro offshore fields will supply the Angola LNG plant, improving Angola's LNG production capacity and the availability of domestic gas for the country's industrial development. Production is scheduled to start in mid-2026.
Quilemba, Angola's first TotalEnergies solar plant
TotalEnergies, alongside the Ministry of Energy and Water as well as its partners Sonangol and Greentech, was also awarded by the Angolan authorities, the concession for the construction of the Quilemba photovoltaic plant, with initial capacity of 35 MWp and the possibility of adding 45 MWp in a second phase.
The plant will be located in the southern city of Lubango and should come on stream at the end of 2023. It will contribute to the decarbonization of Angola’s energy mix and, through a fixed-price Power Purchase Agreement (PPA), deliver significant savings for the Angolan government compared to the fuel used in existing power plants. TotalEnergies holds an 51% interest in Quilemba solar, alongside affiliates of Sonangol EP (30%) and Angola Environment Technology (Greentech, 19%).
"Begonia, NAG1 and Quilemba illustrate the deployment of our multi-energy strategy in Angola, where TotalEnergies has been active for nearly seventy years," said Patrick Pouyanné, Chairman and CEO of TotalEnergies. “With Begonia, the first subsea tieback to another block, we are leveraging the existing Pazflor infrastructure, reducing costs, thanks largely to the standardization of subsea equipment, and continuing to innovate in the deep offshore. With the NAG1 project, we will contribute to the country’s industrial development and enable Angola, from 2026, to increase its LNG production and to contribute to the security of supply of Europe and Asia. Quilemba will allow us to harness the country's solar potential and develop a sustainable model for the production of electricity. These three projects demonstrate TotalEnergies' ambition to support Angola during the energy transition by producing energy with low carbon intensity and developing renewables in a country with strong potential."
Begonia, the first development on Block 17/06
TotalEnergies today announces the final investment decision for Begonia, the first development of block 17/06, located 150 kilometers off the Angolan coast, in agreement with concession holder Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG) and its partners on Block 17/06.
The Begonia development consists of five wells tied back to the Pazflor FPSO (floating production, storage and offloading unit), already in operation on Block 17. After commissioning, expected in late 2024, it will add 30,000 barrels a day to the FPSO's production.
After CLOV Phase 3, another satellite project that produces 30,000 barrels a day and was launched on Block 17 in June 2022, Begonia is the second TotalEnergies-operated project in Angola to use a standardized subsea production system, saving up to 20% on costs and shortening lead times for equipment delivery.
The project represents an investment of $850 million and 1.3 million man-hours of work, 70% of which will be carried out in Angola.
Quiluma and Maboqueiro, Angola's first non-associated natural gas projects
TotalEnergies also announces the final investment decision for the “Non Associated Gas 1” (NAG1) project, in which the Company holds an 11.8% interest alongside its partners, Eni (operator with 25.6%), Chevron (31%), Sonangol P&P (19.8%) and bp (11.8%).
NAG1 is the first non-associated natural gas project developed in Angola. Gas produced from the Quiluma and Maboqueiro offshore fields will supply the Angola LNG plant, improving Angola's LNG production capacity and the availability of domestic gas for the country's industrial development. Production is scheduled to start in mid-2026.
Quilemba, Angola's first TotalEnergies solar plant
TotalEnergies, alongside the Ministry of Energy and Water as well as its partners Sonangol and Greentech, was also awarded by the Angolan authorities, the concession for the construction of the Quilemba photovoltaic plant, with initial capacity of 35 MWp and the possibility of adding 45 MWp in a second phase.
The plant will be located in the southern city of Lubango and should come on stream at the end of 2023. It will contribute to the decarbonization of Angola’s energy mix and, through a fixed-price Power Purchase Agreement (PPA), deliver significant savings for the Angolan government compared to the fuel used in existing power plants. TotalEnergies holds an 51% interest in Quilemba solar, alongside affiliates of Sonangol EP (30%) and Angola Environment Technology (Greentech, 19%).
"Begonia, NAG1 and Quilemba illustrate the deployment of our multi-energy strategy in Angola, where TotalEnergies has been active for nearly seventy years," said Patrick Pouyanné, Chairman and CEO of TotalEnergies. “With Begonia, the first subsea tieback to another block, we are leveraging the existing Pazflor infrastructure, reducing costs, thanks largely to the standardization of subsea equipment, and continuing to innovate in the deep offshore. With the NAG1 project, we will contribute to the country’s industrial development and enable Angola, from 2026, to increase its LNG production and to contribute to the security of supply of Europe and Asia. Quilemba will allow us to harness the country's solar potential and develop a sustainable model for the production of electricity. These three projects demonstrate TotalEnergies' ambition to support Angola during the energy transition by producing energy with low carbon intensity and developing renewables in a country with strong potential."
First Gas introduced at Tinrhert Field Development project in Algeria
A major milestone has been achieved in the delivery of Sonatrach’s Tinrhert Field Development Project in Algeria, with the safe introduction of the first hydrocarbons for the start-up of production. When completed, the development will boost natural gas production capabilities for both local and export markets, enabling economic growth in-country.
Located in Ohanet, around 1,500km southeast of Algiers, Petrofac’s scope of work has included a new inlet separation and compression centre, extending the existing Central Processing Facility which the Company were involved in delivering in 2002. The centre will remove CO2 and mercury from the field’s gas reserves, so the gas is within specifications for the global market. The second part of the project involves the construction of a pipeline network of approximately 400km to connect 36 new wells, along with commissioning, start-up and performance testing of facilities.
Manish Bhojwani, Petrofac’s Algeria Country Manager said:
“The introduction of first gas is a significant step in bringing the project online. The teams are now focused on full start up as we head towards a safe completion. We’re proud that this continues to build on our successful track record, Petrofac has been working to support Algeria’s oil and gas production for more than two decades since our first major contract, the original development here in Ohanet, in 2000.”
Petrofac typically employ more than 800 people in Algeria, more than half of whom are Algerian nationals. Through the Company’s sub-contractors, several thousand more people are generally employed on Petrofac led projects and in 2021, more than 85% were Algerian nationals. Trainees have been recruited locally to support project delivery, with criteria that all are resident in the Ouragla or Ilizi Wilaya regions.
Located in Ohanet, around 1,500km southeast of Algiers, Petrofac’s scope of work has included a new inlet separation and compression centre, extending the existing Central Processing Facility which the Company were involved in delivering in 2002. The centre will remove CO2 and mercury from the field’s gas reserves, so the gas is within specifications for the global market. The second part of the project involves the construction of a pipeline network of approximately 400km to connect 36 new wells, along with commissioning, start-up and performance testing of facilities.
Manish Bhojwani, Petrofac’s Algeria Country Manager said:
“The introduction of first gas is a significant step in bringing the project online. The teams are now focused on full start up as we head towards a safe completion. We’re proud that this continues to build on our successful track record, Petrofac has been working to support Algeria’s oil and gas production for more than two decades since our first major contract, the original development here in Ohanet, in 2000.”
Petrofac typically employ more than 800 people in Algeria, more than half of whom are Algerian nationals. Through the Company’s sub-contractors, several thousand more people are generally employed on Petrofac led projects and in 2021, more than 85% were Algerian nationals. Trainees have been recruited locally to support project delivery, with criteria that all are resident in the Ouragla or Ilizi Wilaya regions.
Thursday 21 July 2022
Liza Unity safely commissioned in industry-leading time, achieves background flare
The gas compression and injection systems on the Liza Unity Floating Production, Storage and Offloading (FPSO) vessel have been safely commissioned in around half normal industry time, achieving background flare as designed and within the 60-day period outlined in the Liza Phase 2 Environmental Permit.
Liza Unity safely commissioned in industry-leading time, achieves background flare
The start-up period involved temporary, non-routine flaring to safely commission the production and gas compression systems.
“This achievement is a testament to the team’s dedication to steady, safe operations. It also demonstrates ExxonMobil’s capabilities as an industry leader and our commitment to operational excellence,” ExxonMobil Guyana Production Manager Mike Ryan said.
The Liza Phase 2 project design eliminates routine flaring by using produced gas to power the FPSO and by reinjecting gas into the reservoir to conserve the gas and to improve oil recovery, thereby reducing emissions compared with traditional methods.
The team was also able to commission the water-injection system, which is now online and operational. The next step is to start up additional new wells in the ramp up to full production of 220,000 barrels of oil per day during the third quarter.
Meanwhile, a new, redesigned Flash Gas Compressor for the Liza Destiny FPSO has arrived in country for installation after extensive testing in Germany. The team is working towards start up in mid-July with the aim of also achieving background flare on that vessel as designed.
“We have relentlessly pursued a solution to this highly complex issue and have never lost sight of that goal. We are pleased that the newly designed machine is now offshore and the teams are methodically removing the original machine in preparation for the upgraded Flash Gas Compressor installation and startup,” the production manager indicated.
Over the last several months, the performance of the second- and third-stage flash gas compressor on the Liza Destiny has been stable and more than 96 percent of the gas produced was reinjected and/or used to power the vessel.
“Recent optimisation tests have confirmed the performance of the previously upgraded equipment and we were able to boost production to more than 140,000 barrels of oil per day, while maintaining the flare rates to a minimum,” Ryan added. “Contrary to reports, with the previously installed machine, production on the Destiny would have had to be zero in order to achieve background flare. Since start up in December 2019, we have managed production in a manner that balances the environmental commitment and economic needs of the country, in alignment with government priorities.”
ExxonMobil Guyana continues to work with the relevant government agencies to ensure compliance with regulations and responsible development of the country’s natural resources.
Liza Unity safely commissioned in industry-leading time, achieves background flare
The start-up period involved temporary, non-routine flaring to safely commission the production and gas compression systems.
“This achievement is a testament to the team’s dedication to steady, safe operations. It also demonstrates ExxonMobil’s capabilities as an industry leader and our commitment to operational excellence,” ExxonMobil Guyana Production Manager Mike Ryan said.
The Liza Phase 2 project design eliminates routine flaring by using produced gas to power the FPSO and by reinjecting gas into the reservoir to conserve the gas and to improve oil recovery, thereby reducing emissions compared with traditional methods.
The team was also able to commission the water-injection system, which is now online and operational. The next step is to start up additional new wells in the ramp up to full production of 220,000 barrels of oil per day during the third quarter.
Meanwhile, a new, redesigned Flash Gas Compressor for the Liza Destiny FPSO has arrived in country for installation after extensive testing in Germany. The team is working towards start up in mid-July with the aim of also achieving background flare on that vessel as designed.
“We have relentlessly pursued a solution to this highly complex issue and have never lost sight of that goal. We are pleased that the newly designed machine is now offshore and the teams are methodically removing the original machine in preparation for the upgraded Flash Gas Compressor installation and startup,” the production manager indicated.
Over the last several months, the performance of the second- and third-stage flash gas compressor on the Liza Destiny has been stable and more than 96 percent of the gas produced was reinjected and/or used to power the vessel.
“Recent optimisation tests have confirmed the performance of the previously upgraded equipment and we were able to boost production to more than 140,000 barrels of oil per day, while maintaining the flare rates to a minimum,” Ryan added. “Contrary to reports, with the previously installed machine, production on the Destiny would have had to be zero in order to achieve background flare. Since start up in December 2019, we have managed production in a manner that balances the environmental commitment and economic needs of the country, in alignment with government priorities.”
ExxonMobil Guyana continues to work with the relevant government agencies to ensure compliance with regulations and responsible development of the country’s natural resources.
Project management services for Aramco's unconventional gas projects
Worley has been awarded two project management service contracts for Aramco’s unconventional gas program in North and South Arabia and Jafurah.
Under the contracts, we will provide front-end engineering design (FEED), detailed design support, project management services and construction management services.
The term of both contracts is three years with an option for an extension for a further two years. We will carry out the work from our Al-Khobar and Houston offices.
“Being part of a project that not only looks towards sustainability but also contributes to boosting regional economy demonstrates Worley’s commitment to developing future growth in the location,” said Eissa Aqeeli, Senior Vice President and Location Director, Saudi Arabia and Bahrain.
Under the contracts, we will provide front-end engineering design (FEED), detailed design support, project management services and construction management services.
The term of both contracts is three years with an option for an extension for a further two years. We will carry out the work from our Al-Khobar and Houston offices.
“Being part of a project that not only looks towards sustainability but also contributes to boosting regional economy demonstrates Worley’s commitment to developing future growth in the location,” said Eissa Aqeeli, Senior Vice President and Location Director, Saudi Arabia and Bahrain.
Monday 18 July 2022
The construction phase of the Greece-Bulgaria interconnector is completed
The construction phase of the gas interconnector Greece-Bulgaria has been completed. The event was celebrated at the gas measuring station near the Greek city of Komotini, where the pipeline connects to the gas transmission network of Greece and to the Trans-Adriatic pipeline. ICGB Executive Officers Teodora Georgieva and Konstantinos Karayannakos jointly announced the finalization of this stage of the IGB project, emphasizing the huge importance of the gas pipeline going way beyond the national borders of Greece and Bulgaria.
The landmark event was attended by the Prime Minister of Bulgaria Kiril Petkov, the Prime Minister of Greece Kyriakos Mitsotakis, the Ministers of Energy of the two countries - Alexander Nikolov and Kostas Skrekas, the Minister of Energy of Azerbaijan Parviz Shahbazov, high-ranking representatives from the European Commission (EC) and by the European Investment Bank (EIB) and a number of officials.
"Today we mark together the completion of a key stage in the development of the energy system in the region taking a big step forward towards a stronger, more connected and independent Europe. The end of the construction of IGB comes after a number of challenges and obstacles that we were able to overcome only thanks to the consistent efforts of the ICGB team, the company's shareholders, the political will of the governments of Bulgaria and Greece and the unequivocal support of the EC", stated the Executive Officer of ICGB from the Bulgarian side Teodora Georgieva. According to her, the upcoming commercial launch of the interconnector will guarantee secure supplies of natural gas from various sources not only for Bulgaria and Greece, but also for the entire region of South-Eastern Europe. "We have the opportunity to supply gas to the Western Balkans, to ensure supplies to Moldova and Ukraine," Georgieva emphasized.
"The IGB is being developed from the very beginning with a number of other key projects such as TAP, TANAP and the Alexandroupolis LNG terminal in mind, and this makes it an integral part of Europe's overall energy strategy and priorities. We began working on this project in a completely different international environment, but today IGB is more necessary and important than ever. The Greece-Bulgaria Interconnector is a new route for secure, diversified supplies, and will reshape the energy map of the region," said ICGB Executive Officer from the Greek side Konstantinos Karayannakos.
Since the second half of June, the interconnector has been filled with test quantities of natural gas. The route and its above-ground infrastructure have already been successfully tested including with transfer of natural gas in the direction of Stara Zagora - Komotini, and since the beginning of July the Komotini station has also been filled up with gas. The integration of the system for automated control and overall management of the gas pipeline (the so-called SCADA system) continues. The SCADA is responsible for transmitting the information and all data necessary for the safe operation of the gas pipeline through the communication network and will provide the capability to the dispatchers to monitor & control the entire facility from a remote centralized control centre. IGB is the first fully automated gas pipeline in Bulgaria.
At the beginning of July, ICGB was successfully certified as an independent transmission operator. This will allow the company to operate commercially after the launch of IGB. For this purpose, within one month, ICGB should introduce a completely new internal management structure with two-level control.The last stage before commercial operation includes the implementation of administrative procedures under the jurisdiction of a number of Bulgarian and Greek institutions, the total duration of which should be significantly reduced in order for the pipeline to become operational as soon as possible. ICGB’s management relies on active institutional support and political will in order for this goal to be successfully reached.
The landmark event was attended by the Prime Minister of Bulgaria Kiril Petkov, the Prime Minister of Greece Kyriakos Mitsotakis, the Ministers of Energy of the two countries - Alexander Nikolov and Kostas Skrekas, the Minister of Energy of Azerbaijan Parviz Shahbazov, high-ranking representatives from the European Commission (EC) and by the European Investment Bank (EIB) and a number of officials.
"Today we mark together the completion of a key stage in the development of the energy system in the region taking a big step forward towards a stronger, more connected and independent Europe. The end of the construction of IGB comes after a number of challenges and obstacles that we were able to overcome only thanks to the consistent efforts of the ICGB team, the company's shareholders, the political will of the governments of Bulgaria and Greece and the unequivocal support of the EC", stated the Executive Officer of ICGB from the Bulgarian side Teodora Georgieva. According to her, the upcoming commercial launch of the interconnector will guarantee secure supplies of natural gas from various sources not only for Bulgaria and Greece, but also for the entire region of South-Eastern Europe. "We have the opportunity to supply gas to the Western Balkans, to ensure supplies to Moldova and Ukraine," Georgieva emphasized.
"The IGB is being developed from the very beginning with a number of other key projects such as TAP, TANAP and the Alexandroupolis LNG terminal in mind, and this makes it an integral part of Europe's overall energy strategy and priorities. We began working on this project in a completely different international environment, but today IGB is more necessary and important than ever. The Greece-Bulgaria Interconnector is a new route for secure, diversified supplies, and will reshape the energy map of the region," said ICGB Executive Officer from the Greek side Konstantinos Karayannakos.
Since the second half of June, the interconnector has been filled with test quantities of natural gas. The route and its above-ground infrastructure have already been successfully tested including with transfer of natural gas in the direction of Stara Zagora - Komotini, and since the beginning of July the Komotini station has also been filled up with gas. The integration of the system for automated control and overall management of the gas pipeline (the so-called SCADA system) continues. The SCADA is responsible for transmitting the information and all data necessary for the safe operation of the gas pipeline through the communication network and will provide the capability to the dispatchers to monitor & control the entire facility from a remote centralized control centre. IGB is the first fully automated gas pipeline in Bulgaria.
At the beginning of July, ICGB was successfully certified as an independent transmission operator. This will allow the company to operate commercially after the launch of IGB. For this purpose, within one month, ICGB should introduce a completely new internal management structure with two-level control.The last stage before commercial operation includes the implementation of administrative procedures under the jurisdiction of a number of Bulgarian and Greek institutions, the total duration of which should be significantly reduced in order for the pipeline to become operational as soon as possible. ICGB’s management relies on active institutional support and political will in order for this goal to be successfully reached.
Monday 4 July 2022
Dnex’s Subsidiary Ping Takes Delivery Of FPSO For The Avalon Development
Dagang NeXchange Berhad (“DNeX”), via its subsidiary Ping Petroleum UK PLC (“Ping”), has taken delivery of the Sevan Hummingbird Floating Production Storage and Offloading (“FPSO”) vessel from marine energy transportation company, Teekay Corporation.
Acquisition of the FPSO is a critical milestone in the Central North Sea Avalon Development Project, which the company continues to progress after receiving a letter of “no objections” from the North Sea Transition Authority (“NSTA”) in March this year for its proposed Avalon development plans.
Ping has also been recently granted a 19-month extension by NSTA to the second term of the P2006 licence containing Avalon. This allows the company additional time to optimise and gain full regulatory approval of the Avalon Field Development Plan.
The proposed development concept includes plans to deploy the Sevan Hummingbird FPSO at the Avalon field which will be modified to facilitate electrification from an external, low-carbon source. The company is evaluating options to connect the FPSO to a dedicated floating offshore wind turbine to power the facility, minimising diesel usage and associated Greenhouse Gas emissions. The planned development allows Ping to expand and diversify its portfolio of producing assets in full compliance with the UK’s energy security and Net Zero targets.
Tan Sri Syed Zainal Abidin Syed Mohamed Tahir, Group Managing Director of DNeX, said the acquisition of the Sevan Hummingbird FPSO is a key milestone for the Avalon oilfield and that the Group anticipates full operational deployment of the facility on Avalon by 2025.
“We have a tangible asset ready with the newly acquired Sevan Hummingbird. Our next step is to secure approval for our Field Development Plan, which will be submitted in the coming months,” he said.
First commissioned in 2008, the Sevan Hummingbird FPSO is a 60 metre-diameter facility, which has a storage capacity of 270,000 barrels of oil and is capable of producing up to 30,000 barrels of oil per day, supporting up to 47 offshore personnel.
With a total estimated ultimate recovery (“EUR”) of 23 million barrels of oil reserves over a period of 12 years, oil production from Ping’s second oilfield asset is expected to come onstream in 2025.
Acquisition of the FPSO is a critical milestone in the Central North Sea Avalon Development Project, which the company continues to progress after receiving a letter of “no objections” from the North Sea Transition Authority (“NSTA”) in March this year for its proposed Avalon development plans.
Ping has also been recently granted a 19-month extension by NSTA to the second term of the P2006 licence containing Avalon. This allows the company additional time to optimise and gain full regulatory approval of the Avalon Field Development Plan.
The proposed development concept includes plans to deploy the Sevan Hummingbird FPSO at the Avalon field which will be modified to facilitate electrification from an external, low-carbon source. The company is evaluating options to connect the FPSO to a dedicated floating offshore wind turbine to power the facility, minimising diesel usage and associated Greenhouse Gas emissions. The planned development allows Ping to expand and diversify its portfolio of producing assets in full compliance with the UK’s energy security and Net Zero targets.
Tan Sri Syed Zainal Abidin Syed Mohamed Tahir, Group Managing Director of DNeX, said the acquisition of the Sevan Hummingbird FPSO is a key milestone for the Avalon oilfield and that the Group anticipates full operational deployment of the facility on Avalon by 2025.
“We have a tangible asset ready with the newly acquired Sevan Hummingbird. Our next step is to secure approval for our Field Development Plan, which will be submitted in the coming months,” he said.
First commissioned in 2008, the Sevan Hummingbird FPSO is a 60 metre-diameter facility, which has a storage capacity of 270,000 barrels of oil and is capable of producing up to 30,000 barrels of oil per day, supporting up to 47 offshore personnel.
With a total estimated ultimate recovery (“EUR”) of 23 million barrels of oil reserves over a period of 12 years, oil production from Ping’s second oilfield asset is expected to come onstream in 2025.
Thursday 23 June 2022
Chevron Sanctions Ballymore Project in Deepwater U.S. Gulf of Mexico
Chevron Corporation (NYSE: CVX) announced today it has sanctioned the Ballymore project in the deepwater U.S. Gulf of Mexico. The project, with a design capacity of 75,000 barrels of crude oil per day, will be developed as a three-mile subsea tieback to the existing Chevron-operated Blind Faith platform.
“Chevron’s U.S. Gulf of Mexico production is some of the lowest carbon intensity production in our portfolio at around 6 kg CO2 equivalent per barrel of oil equivalent and is a fraction of the global industry average,” said Steve Green, president of Chevron North America Exploration and Production. “Once complete, Ballymore is expected to add a reliable supply of U.S.-produced energy to help meet global demand. The project is designed to lower development costs by using a subsea tieback approach, standardized equipment and repeatable engineering solutions – leveraging existing operated infrastructure.”
Ballymore will be Chevron’s first development in the Norphlet trend of the U.S. gulf. The project will be in the Mississippi Canyon area in around 6,600 feet (2,000 m) of water, about 160 miles (260 km) southeast of New Orleans. Potentially recoverable oil-equivalent resources for Ballymore are estimated at more than 150 million barrels.
The project, which involves three production wells tied back via one flowline to the nearby Blind Faith facility, will require an investment of approximately $1.6 billion. Oil and natural gas production will be transported via existing infrastructure. First oil is expected in 2025.
Chevron subsidiary Chevron U.S.A. Inc. is the operator of the Ballymore project with a 60 percent working interest. Co-owner TotalEnergies E&P USA, Inc. has a 40 percent interest.
“Chevron’s U.S. Gulf of Mexico production is some of the lowest carbon intensity production in our portfolio at around 6 kg CO2 equivalent per barrel of oil equivalent and is a fraction of the global industry average,” said Steve Green, president of Chevron North America Exploration and Production. “Once complete, Ballymore is expected to add a reliable supply of U.S.-produced energy to help meet global demand. The project is designed to lower development costs by using a subsea tieback approach, standardized equipment and repeatable engineering solutions – leveraging existing operated infrastructure.”
Ballymore will be Chevron’s first development in the Norphlet trend of the U.S. gulf. The project will be in the Mississippi Canyon area in around 6,600 feet (2,000 m) of water, about 160 miles (260 km) southeast of New Orleans. Potentially recoverable oil-equivalent resources for Ballymore are estimated at more than 150 million barrels.
The project, which involves three production wells tied back via one flowline to the nearby Blind Faith facility, will require an investment of approximately $1.6 billion. Oil and natural gas production will be transported via existing infrastructure. First oil is expected in 2025.
Chevron subsidiary Chevron U.S.A. Inc. is the operator of the Ballymore project with a 60 percent working interest. Co-owner TotalEnergies E&P USA, Inc. has a 40 percent interest.
Monday 13 June 2022
bp reshapes Canada portfolio for strong future growth
bp will increase its acreage position offshore Eastern Canada and sell its 50% non-operated interest in the Sunrise oil sands project in an agreement reached with Calgary-based Cenovus Energy.
Total consideration for the transaction includes C$600 million (Canadian dollars) cash, a contingent payment with a maximum aggregate value of C$600 million expiring after two years, and Cenovus’s 35% position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador.
Starlee Sykes, bp senior vice president, Gulf of Mexico & Canada, said: “This is an important step in our plans to create a more focused, resilient and competitive business in Canada. Bay du Nord will add sizeable acreage and a discovered resource to our existing portfolio offshore Newfoundland and Labrador. Along with bp’s active Canadian marketing and trading business, this will position bp Canada for strong future growth.”
In Canada, bp will no longer have interests in oil sands production and will shift its focus to future potential offshore growth. bp currently holds an interest in six exploration licenses in the offshore Eastern Newfoundland Region. The non-operated stake in the Bay du Nord project will expand bp’s position offshore Eastern Canada.
Subject to regulatory approvals, the transaction is expected to close in 2022.
Notes to editors
Total consideration for the transaction includes C$600 million (Canadian dollars) cash, a contingent payment with a maximum aggregate value of C$600 million expiring after two years, and Cenovus’s 35% position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador.
Starlee Sykes, bp senior vice president, Gulf of Mexico & Canada, said: “This is an important step in our plans to create a more focused, resilient and competitive business in Canada. Bay du Nord will add sizeable acreage and a discovered resource to our existing portfolio offshore Newfoundland and Labrador. Along with bp’s active Canadian marketing and trading business, this will position bp Canada for strong future growth.”
In Canada, bp will no longer have interests in oil sands production and will shift its focus to future potential offshore growth. bp currently holds an interest in six exploration licenses in the offshore Eastern Newfoundland Region. The non-operated stake in the Bay du Nord project will expand bp’s position offshore Eastern Canada.
Subject to regulatory approvals, the transaction is expected to close in 2022.
Notes to editors
- The Bay du Nord (BdN) project consists of several oil discoveries in the Flemish Pass Basin, some 500 km northeast of St. John’s in Newfoundland and Labrador, Canada.
- The project area is in water depths of approximately 1,200m, with recoverable reserves estimated to be about 300 million barrels of oil.
- bp Canada Energy Group ULC (“bp”) holds offshore exploration licenses in the Orphan Basin and is planning to drill an initial exploration well called Ephesus in 2023.
- The Sunrise oil sands project, operated by Cenovus, is located 40 miles east of Fort McMurray, Alberta and employs steam-assisted gravity drainage to produce bitumen. It has a nameplate capacity of 60,000 bbls/day.
Wednesday 25 May 2022
Wintershall Dea exits Brage oil field
Wintershall Dea is divesting its ownership of the Brage field and transferring the operatorship to the mid-late life specialist operator OKEA. In the next chapter of Wintershall Dea’s story in Norway the company will build on its strength as one of the largest subsea operators on the shelf.
"Norway is and remains an important core region for Wintershall Dea's production in our global portfolio," said Dawn Summers, Chief Operating Officer at Wintershall Dea. "With the sale of our interests in Brage and Ivar Aasen, we are further strengthening our focus in Norway on gas production. Here we already have a strong position in the country, and our major projects Dvalin and Njord, that are planned to come on stream by the end of 2022, will add further gas volumes that secure energy supply in Europe”, Summers added.
As part of the agreement, OKEA purchases Wintershall Dea’s 35.2% share in the Brage field and 6.46% share in the Ivar Aasen field, as well as 6% of the Nova development for €108 million (NOK 1.1 billion). In addition, payments linked to the fulfilment of certain conditions are part of the transaction.
FOCUS ON FURTHER GAS VOLUMES
“We remain one of the biggest producers in Norway, and one of the largest exporters of gas, while also robustly shaping our business for the opportunities we see coming on the shelf,” said Managing Director at Wintershall Dea Norge, Michael Zechner. “Through this agreement, we have not only realised value for our assets and exited the operatorship of Brage in favour of a company which specialises in mid-late life fields, we have also gained a valuable partner in our operated Nova license”, Zechner underlined. In Norway, Wintershall Dea will put an even stronger focus on exploration, development, and production in core areas, to continuously develop a low-carbon asset portfolio and position the company within carbon management and hydrogen.
Wintershall Dea's total production in Norway was 159,000 barrels of oil equivalent per day in 2021, more than half of which was natural gas. Volumes from upcoming projects Nova, Njord and Dvalin will add around 70,000 to 80,000 boe/d. Production from Brage and Ivar Aasen totalled around 6,000 boe per day.
STRENGTHENING EFFICIENT AND LOW-CARBON SUBSEA PRODUCTION
Wintershall Dea is moving forward on the Norwegian Continental Shelf as a leading subsea operator with a focus on gas and carbon management projects. The company is committed to having net zero upstream activities by 20301 by increasingly focusing on assets with a low carbon footprint and strict emissions management. The gas-weighted company is already the third largest subsea operator by number of fields in Norway and is now also pursuing carbon management opportunities on the shelf.
Subject to customary approval by authorities the deal is expected to be completed in Q4 2022. The transaction will then be effective retroactively from 1.1.2022.
FIELD SHARES AFTER COMPLETED TRANSACTION:
Brage fieldLocated in the northern part of the North Sea, 123 kilometres west of Bergen, with a water depth of 140 metres.
Discovered in 1980 and production start in 1993.
The field has been developed with an integrated production, drilling and accommodation facility with a steel jacket.
The oil is transported by pipeline to the Oseberg field and further through the Oseberg Transport System (OTS) pipeline to the Sture terminal. A gas pipeline is tied-back to Statpipe.
OKEA will take over Wintershall Dea Norge AS’s entire share (35.2%) as well as the operatorship, with other partners comprising of Lime Petroleum AS (33.84%), DNO Norge AS (14.26%), Vår Energi ASA (12.26%) and M Vest Energy AS (4.44%).
Ivar Aasen fieldLocated at a water depth of 110 metres in the northern part of the North Sea, 30 kilometres south of Grane and Balder.
Discovered in 2008, and the plan for development and operation (PDO) was approved in 2013. Production started in 2016.
The development includes a production, drilling and housing facility (PDQ) with a steel substructure and a separate jack-up rig for drilling and completion. Ivar Aasen is powered by electricity from Edvard Grieg and will be supplied with power from shore as part of the joint development of Utsira High expected to commence in late 2022.
Aker BP is the operator (34.79%), with other partners comprising Equinor Energy AS (41.47%), Spirit Energy Norway AS (12.32%), Lundin Energy Norway AS (1.39%), M Vest Energy AS (0.80%) and after the transaction has been completed OKEA will own 9.23%.
Nova fieldLocated in the northern part of the North Sea, 45 kilometres west of Florø and 17 kilometres southwest of the Gjøa field with a water depth of 370 metres.
Nova was discovered in 2012, and the plan for development and operation (PDO) was approved in 2018. The development consists of two four-slot subsea templates tied back to the Gjøa host platform wherefrom Nova will be provided with green power from shore. The subsea installation scope was finalised in 2021.
The field is under development, and production is planned in the second half of 2022.
The well stream will be routed to the Gjøa platform for processing and export. The oil will be transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
After the transaction has been completed Wintershall Dea Norge AS as the operator will own 39%, with other partners comprising OKEA (6%), Sval Energi AS (25%), Spirit Energy Norway (20%) and ONE-Dyas Norge AS (10%).
"Norway is and remains an important core region for Wintershall Dea's production in our global portfolio," said Dawn Summers, Chief Operating Officer at Wintershall Dea. "With the sale of our interests in Brage and Ivar Aasen, we are further strengthening our focus in Norway on gas production. Here we already have a strong position in the country, and our major projects Dvalin and Njord, that are planned to come on stream by the end of 2022, will add further gas volumes that secure energy supply in Europe”, Summers added.
As part of the agreement, OKEA purchases Wintershall Dea’s 35.2% share in the Brage field and 6.46% share in the Ivar Aasen field, as well as 6% of the Nova development for €108 million (NOK 1.1 billion). In addition, payments linked to the fulfilment of certain conditions are part of the transaction.
FOCUS ON FURTHER GAS VOLUMES
“We remain one of the biggest producers in Norway, and one of the largest exporters of gas, while also robustly shaping our business for the opportunities we see coming on the shelf,” said Managing Director at Wintershall Dea Norge, Michael Zechner. “Through this agreement, we have not only realised value for our assets and exited the operatorship of Brage in favour of a company which specialises in mid-late life fields, we have also gained a valuable partner in our operated Nova license”, Zechner underlined. In Norway, Wintershall Dea will put an even stronger focus on exploration, development, and production in core areas, to continuously develop a low-carbon asset portfolio and position the company within carbon management and hydrogen.
Wintershall Dea's total production in Norway was 159,000 barrels of oil equivalent per day in 2021, more than half of which was natural gas. Volumes from upcoming projects Nova, Njord and Dvalin will add around 70,000 to 80,000 boe/d. Production from Brage and Ivar Aasen totalled around 6,000 boe per day.
STRENGTHENING EFFICIENT AND LOW-CARBON SUBSEA PRODUCTION
Wintershall Dea is moving forward on the Norwegian Continental Shelf as a leading subsea operator with a focus on gas and carbon management projects. The company is committed to having net zero upstream activities by 20301 by increasingly focusing on assets with a low carbon footprint and strict emissions management. The gas-weighted company is already the third largest subsea operator by number of fields in Norway and is now also pursuing carbon management opportunities on the shelf.
Subject to customary approval by authorities the deal is expected to be completed in Q4 2022. The transaction will then be effective retroactively from 1.1.2022.
FIELD SHARES AFTER COMPLETED TRANSACTION:
Brage fieldLocated in the northern part of the North Sea, 123 kilometres west of Bergen, with a water depth of 140 metres.
Discovered in 1980 and production start in 1993.
The field has been developed with an integrated production, drilling and accommodation facility with a steel jacket.
The oil is transported by pipeline to the Oseberg field and further through the Oseberg Transport System (OTS) pipeline to the Sture terminal. A gas pipeline is tied-back to Statpipe.
OKEA will take over Wintershall Dea Norge AS’s entire share (35.2%) as well as the operatorship, with other partners comprising of Lime Petroleum AS (33.84%), DNO Norge AS (14.26%), Vår Energi ASA (12.26%) and M Vest Energy AS (4.44%).
Ivar Aasen fieldLocated at a water depth of 110 metres in the northern part of the North Sea, 30 kilometres south of Grane and Balder.
Discovered in 2008, and the plan for development and operation (PDO) was approved in 2013. Production started in 2016.
The development includes a production, drilling and housing facility (PDQ) with a steel substructure and a separate jack-up rig for drilling and completion. Ivar Aasen is powered by electricity from Edvard Grieg and will be supplied with power from shore as part of the joint development of Utsira High expected to commence in late 2022.
Aker BP is the operator (34.79%), with other partners comprising Equinor Energy AS (41.47%), Spirit Energy Norway AS (12.32%), Lundin Energy Norway AS (1.39%), M Vest Energy AS (0.80%) and after the transaction has been completed OKEA will own 9.23%.
Nova fieldLocated in the northern part of the North Sea, 45 kilometres west of Florø and 17 kilometres southwest of the Gjøa field with a water depth of 370 metres.
Nova was discovered in 2012, and the plan for development and operation (PDO) was approved in 2018. The development consists of two four-slot subsea templates tied back to the Gjøa host platform wherefrom Nova will be provided with green power from shore. The subsea installation scope was finalised in 2021.
The field is under development, and production is planned in the second half of 2022.
The well stream will be routed to the Gjøa platform for processing and export. The oil will be transported further through the Troll Oil Pipeline II to the Mongstad terminal, and the gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK.
After the transaction has been completed Wintershall Dea Norge AS as the operator will own 39%, with other partners comprising OKEA (6%), Sval Energi AS (25%), Spirit Energy Norway (20%) and ONE-Dyas Norge AS (10%).
Thursday 21 April 2022
Petrobras and Equinor start production on IOR project at Roncador, Brazil
Petrobras, the operator, and Equinor successfully started production from the first two wells of the increased oil recovery (IOR) project at Roncador.
This represents an important milestone in the development of the field, increasing recovery rates, adding valuable production and demonstrating the potential to leverage new technology.
The two wells are the first of a series of IOR wells to reach production. Start-up is almost five months ahead of schedule and at half of the planned cost. The wells add a combined ~20,000 barrels of oil equivalent per day to Roncador, bringing daily production to approximately 150,000 barrels and reducing the carbon intensity (emissions per barrel produced) of the field.
Through this first IOR project, the partnership will drill 18 wells, which are expected to provide additional recoverable resources of 160 million barrels. Improvements in well design and the partners’ combined technological experience are the main drivers behind the 50% cost reduction across the first six wells, including the two in production.
Roncador is Brazil’s fifth largest producing asset and has been in production since 1999. Petrobras is the operator of the field (75% equity) with Equinor (25% equity) entering the project in 2018 as a strategic partner.
“This milestone demonstrates the partnership’s ability to increase production and value through technology. We will continue combining our capabilities to improve recovery from Roncador and extract further value from the field. Petrobras will leverage its experience as one of the largest deep-water operators and pre-salt developers in the world and Equinor will draw on its technology, expertise and decades of experience in IOR on the Norwegian Continental Shelf,” says Veronica Coelho, Equinor country manager for Brazil.
In addition to the planned 18 IOR wells, the partnership believes it can improve recovery further and aims to increase recoverable resources by a total of 1 billion barrels of oil equivalent. The field has more than 10 billion barrels of oil equivalent in place, under a license lasting until 2052. The strategic alliance agreement also includes an energy efficiency and CO2 emissions reduction program for Roncador.
Thursday 31 March 2022
MOL divests Upstream assets in the UK
MOL today signed an agreement with Waldorf Production Limited (“Waldorf”) covering the sale of its entire Upstream portfolio in the United Kingdom.
The divested offshore assets include MOL’s 20% stake in the Catcher field, a 50% stake in Scolty & Crathes and a 21.8% stake in Scott as well as stakes in a number of other licences. MOL’s UK working interest production peaked above 18 mboepd in 2019 and has been falling in the last two years, accordingly Q4 2021 production was marginally above 12 mboepd. MOL’s corresponding proved and probable reserves (SPE 2P) amounted to 14.9 MMboe at the end of 2021.
Waldorf offered a base cash consideration of USD 305mn, which is subject to customary purchase price adjustments and is based on an economic effective date of January 1, 2021. In addition, the agreement contains an earn-out scheme mainly dependent on oil prices during 2022-2025.
As a result of the transaction, Waldorf will retain all future field abandonment liabilities such that on completion MOL will derecognise provisions of around USD 350mn. Furthermore, MOL’s average lifting cost will improve following completion of the transaction, as the production costs of the UK assets exceed the average lifting costs of the rest of MOL’s E&P portfolio.
The closing of the transaction is subject to obtaining necessary approvals and is expected to take place in the second half of 2022.
List of divested assets:
- Greater Catcher Area 20.00%
Scott 21.83%
Telford 1.59%
Rochelle 20.71%
Scolty & Crathes 50.00%
Broom 29.00%
Cladhan 33.50%*
Brent Pipeline System 1.77%
Sullom Voe Terminal 0.72%
Monday 31 January 2022
TotalEnergies sells minority interests in West of Shetland fields
TotalEnergies has signed an agreement to sell to Kistos Energy Limited a 20% interest in the Greater Laggan Area fields and in the Shetland Gas Plant in the UK, as well as interests in several nearby exploration licenses.
The transaction price includes a firm consideration of 125 M$, as well as two contingent payments, the first one up to 40 M$ depending on the gas price in 2022, and the second one in the event of development of a discovery on an exploration license.
The transaction is subject to the approval of the UK authorities.
The Greater Laggan Area comprises the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, located around 140 kilometers west of the Shetland Islands, at water depths of 300 to 600 meters. Development of the fields was launched in 2010 and production start-up was achieved in 2016. Production from the 20% interest sold to Kistos Energy Limited was about 8,000 barrels of oil equivalent per day in 2021.
Following completion of the transaction, TotalEnergies E&P UK Limited will hold a 40% operated interest in the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, including infield facilities and the onshore Shetland Gas Plant, alongside partners Kistos Energy Limited (20%), Ineos E&P UK Limited (20%) and RockRose UKCS15 Limited (20%).
The transaction price includes a firm consideration of 125 M$, as well as two contingent payments, the first one up to 40 M$ depending on the gas price in 2022, and the second one in the event of development of a discovery on an exploration license.
The transaction is subject to the approval of the UK authorities.
The Greater Laggan Area comprises the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, located around 140 kilometers west of the Shetland Islands, at water depths of 300 to 600 meters. Development of the fields was launched in 2010 and production start-up was achieved in 2016. Production from the 20% interest sold to Kistos Energy Limited was about 8,000 barrels of oil equivalent per day in 2021.
Following completion of the transaction, TotalEnergies E&P UK Limited will hold a 40% operated interest in the Laggan, Tormore, Glenlivet, Edradour and Glendronach fields, including infield facilities and the onshore Shetland Gas Plant, alongside partners Kistos Energy Limited (20%), Ineos E&P UK Limited (20%) and RockRose UKCS15 Limited (20%).
Wednesday 26 January 2022
TotalEnergies withdraws from Myanmar
Following the coup of 1st February 2021 in Myanmar, TotalEnergies has firmly condemned on several occasions the abuses and human rights violations taking place there. Since then, our Company's decisions have been guided by clear principles: to halt all our ongoing projects, but to continue to produce gas from the Yadana field, which is essential for supplying electricity to the local Burmese and Thai population, to protect our employees from the risk of criminal prosecution or forced labour, and, insofar as is materially and legally possible, to limit the financial flows received by the national oil company MOGE.
Despite the actions taken, TotalEnergies has not been able to meet the expectations of many stakeholders (shareholders, international and Burmese civil society organisations), who are calling to stop the revenues going to the Burmese state through the state-owned company MOGE from the Yadana field production. In fact, this is materially impossible for TotalEnergies, as most of the payments for the sale of the gas are made directly by the Thai company PTT, the buyer of the exported gas. TotalEnergies has also approached the French authorities to consider putting in place targeted sanctions that would confine all the financial flows of the various partners to escrow accounts without shutting down the gas production. TotalEnergies has not identified any means for doing so.
While our Company considers that its presence in a country allows it to promote its values, including outside its direct sphere of operations, the situation, in terms of human rights and more generally the rule of law, which have kept worsening in Myanmar since the coup of February 2021, has led us to reassess the situation and no longer allows TotalEnergies to make a sufficiently positive contribution in the country.
As a result, TotalEnergies has decided to initiate the contractual process of withdrawing from the Yadana field and from MGTC in Myanmar, both as operator and as shareholder, without any financial compensation for TotalEnergies. This withdrawal has been notified today to TotalEnergies' partners in Yadana and MGTC and will be effective at the latest at the expiry of the 6-month contractual period. The agreements also stipulate that, in the event of withdrawal, TotalEnergies' interests will be shared between the current partners, unless they object to such allocation, and that the role of operator will be taken over by one of the partners.
During this notice period, TotalEnergies will continue to act as a responsible operator in order to ensure the continuity of gas deliveries for the benefit of the population. TotalEnergies has indicated to its partners its willingness to ease the transition to the new operator and facilitate the transfer of staff who so wish.
***
About TotalEnergies in Myanmar
TotalEnergies has been a partner (31.24%) and operator of the Yadana gas field (Blocks M5 and M6) in Myanmar since 1992, alongside its partners Unocal-Chevron (28.26%), PTTEP (25.5%), a subsidiary of the Thai national energy company PTT, and the Burmese state-owned company MOGE (15%).
The Yadana field produces around 6 billion cubic meters per year of gas of which about 70% is exported to Thailand where it is sold to the national company PTT and 30% to the national company MOGE for domestic use. This gas helps to provide about half of the electricity in the Burmese capital Yangoon and supplies the western part of Thailand. Gas is exported to Thailand through a pipeline operated by MGTC that carries gas from the Yadana field to the Burmese-Thai border, over 400 kilometers. The shareholders of MGTC are the same as the partners in the Yadana field and in the same proportions.
Despite the actions taken, TotalEnergies has not been able to meet the expectations of many stakeholders (shareholders, international and Burmese civil society organisations), who are calling to stop the revenues going to the Burmese state through the state-owned company MOGE from the Yadana field production. In fact, this is materially impossible for TotalEnergies, as most of the payments for the sale of the gas are made directly by the Thai company PTT, the buyer of the exported gas. TotalEnergies has also approached the French authorities to consider putting in place targeted sanctions that would confine all the financial flows of the various partners to escrow accounts without shutting down the gas production. TotalEnergies has not identified any means for doing so.
While our Company considers that its presence in a country allows it to promote its values, including outside its direct sphere of operations, the situation, in terms of human rights and more generally the rule of law, which have kept worsening in Myanmar since the coup of February 2021, has led us to reassess the situation and no longer allows TotalEnergies to make a sufficiently positive contribution in the country.
As a result, TotalEnergies has decided to initiate the contractual process of withdrawing from the Yadana field and from MGTC in Myanmar, both as operator and as shareholder, without any financial compensation for TotalEnergies. This withdrawal has been notified today to TotalEnergies' partners in Yadana and MGTC and will be effective at the latest at the expiry of the 6-month contractual period. The agreements also stipulate that, in the event of withdrawal, TotalEnergies' interests will be shared between the current partners, unless they object to such allocation, and that the role of operator will be taken over by one of the partners.
During this notice period, TotalEnergies will continue to act as a responsible operator in order to ensure the continuity of gas deliveries for the benefit of the population. TotalEnergies has indicated to its partners its willingness to ease the transition to the new operator and facilitate the transfer of staff who so wish.
***
About TotalEnergies in Myanmar
TotalEnergies has been a partner (31.24%) and operator of the Yadana gas field (Blocks M5 and M6) in Myanmar since 1992, alongside its partners Unocal-Chevron (28.26%), PTTEP (25.5%), a subsidiary of the Thai national energy company PTT, and the Burmese state-owned company MOGE (15%).
The Yadana field produces around 6 billion cubic meters per year of gas of which about 70% is exported to Thailand where it is sold to the national company PTT and 30% to the national company MOGE for domestic use. This gas helps to provide about half of the electricity in the Burmese capital Yangoon and supplies the western part of Thailand. Gas is exported to Thailand through a pipeline operated by MGTC that carries gas from the Yadana field to the Burmese-Thai border, over 400 kilometers. The shareholders of MGTC are the same as the partners in the Yadana field and in the same proportions.
Friday 21 January 2022
TechnipFMC Awarded Integrated EPCI (iEPCI™) Contract by Equinor
TechnipFMC (NYSE: FTI) (PARIS: FTI) has been awarded an integrated Engineering, Procurement, Construction and Installation (iEPCI™) contract(1) for Equinor’s Smørbukk Nord development.
The contract covers a high-pressure, high-temperature subsea production system and associated equipment for a brownfield tieback in the Åsgard field in the Norwegian Continental Shelf, where TechnipFMC has a large installed base. The award follows front end engineering and design work on the project in 2021.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Our ability to deliver this optimized solution for Equinor is possible due to our close collaboration with the client, portfolio of subsea equipment, and integrated execution model. We’re delighted to be once again delivering an iEPCI™ project for Equinor.”
The installation campaign will use TechnipFMC’s battery hybrid vessel, which will reduce greenhouse gas emissions through reduced fuel consumption.
The contract covers a high-pressure, high-temperature subsea production system and associated equipment for a brownfield tieback in the Åsgard field in the Norwegian Continental Shelf, where TechnipFMC has a large installed base. The award follows front end engineering and design work on the project in 2021.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Our ability to deliver this optimized solution for Equinor is possible due to our close collaboration with the client, portfolio of subsea equipment, and integrated execution model. We’re delighted to be once again delivering an iEPCI™ project for Equinor.”
The installation campaign will use TechnipFMC’s battery hybrid vessel, which will reduce greenhouse gas emissions through reduced fuel consumption.
Tuesday 11 January 2022
Eni awarded five Exploration Licenses in Egypt
Eni has been awarded five new exploration licenses by the Egyptian Ministry of Petroleum. The licenses, four of which as Operator, are in the Egyptian offshore and onshore, and follow the successful participation to the 2021 competitive “Egypt International Bid Round for Petroleum Exploration and Exploitation” which was previously announced by the Egyptian General Petroleum Corporation and the Egyptian Natural Gas Holding Company through the Egypt Exploration and Production Gateway.
The licenses are located in the Eastern Mediterranean Sea (Block “EGY-MED-E5” in partnership with BP 50%-50% and Block “EGY-MED-E6” IEOC 100%), in the Gulf of Suez (Block “EGY-GOS-13” IEOC 100%) and in the Western Desert (Blocks “Egy-WD- 7” in partnership with APEX 50%-50% and “EGY-WD-9” IEOC 100%) with a total acreage of about 8,410 sqkm. The licenses are placed within prolific basins with proved petroleum systems able to generate liquid and gaseous hydrocarbons and can also rely on nearby existing producing and processing facilities and on a demanding market that will allow a quick valorization of the potential exploration discoveries.
The bid results are aligned with Eni’s strategy to keep exploring and producing gas to sustain the Egyptian domestic market and contribute to LNG export, thanks to the recent restart of the Damietta LNG plant.
Eni has been present in Egypt since 1954 and is currently the country's main producer with equity hydrocarbon production of around 350,000 barrels of oil equivalent per day.
The licenses are located in the Eastern Mediterranean Sea (Block “EGY-MED-E5” in partnership with BP 50%-50% and Block “EGY-MED-E6” IEOC 100%), in the Gulf of Suez (Block “EGY-GOS-13” IEOC 100%) and in the Western Desert (Blocks “Egy-WD- 7” in partnership with APEX 50%-50% and “EGY-WD-9” IEOC 100%) with a total acreage of about 8,410 sqkm. The licenses are placed within prolific basins with proved petroleum systems able to generate liquid and gaseous hydrocarbons and can also rely on nearby existing producing and processing facilities and on a demanding market that will allow a quick valorization of the potential exploration discoveries.
The bid results are aligned with Eni’s strategy to keep exploring and producing gas to sustain the Egyptian domestic market and contribute to LNG export, thanks to the recent restart of the Damietta LNG plant.
Eni has been present in Egypt since 1954 and is currently the country's main producer with equity hydrocarbon production of around 350,000 barrels of oil equivalent per day.
Monday 10 January 2022
McDermott Wins Scarborough EPCIC Contract
After successfully completing the Front-End Engineering Design (FEED) for the Scarborough Project, McDermott International has been awarded a contract by Woodside, as Operator for and on behalf of the Scarborough Joint Venture, for the engineering, procurement, construction, installation and commissioning (EPCIC) services for its Floating Production Unit (FPU) offshore Western Australia. The integrated scope also includes the design, fabrication, integration, transportation and installation of the hull and topsides.
"McDermott brings the engineering and execution expertise to deliver integrated deepwater subsea projects and offshore FPUs to the highest standards," said Samik Mukherjee, Executive Vice President and Chief Operating Officer. "After a long engagement on the project, the collaborative execution model with Woodside—from pre-FEED through to EPCIC—de-risks execution. Further, the facilities incorporate energy efficiency in design to reduce Scarborough's offshore emissions."
The topside, which will be approximately 30,000 tons, will be fabricated by McDermott's joint venture fabrication yard, Qingdao McDermott Wuchuan, in China. The project scope includes a battery energy storage system to reduce emissions on the topsides and support Woodside's net emissions reduction targets.
"McDermott will apply our long history of successful integrated project delivery for the Scarborough Project, along with our deepwater expertise and industry-leading health and safety standards to drive this incredible project to completion," said Mahesh Swaminathan, Senior Vice President, Asia Pacific.
Engineering expertise will be leveraged from McDermott's Kuala Lumpur and Gurgaon offices, with McDermott's long-established subsea team in Perth supporting transport, installation, hook up and commissioning activities.
The FPU processes natural gas, which includes gas separation, dehydration and compression as well as mono ethylene glycol regeneration and produced-water handling. Designed for a production capacity of up to 1.8 billion standard cubic feet per day, the topside will be connected to the semi-submersible hull and pre-commissioned prior to transportation and installation in a water depth of 3,100 feet (950 meters), approximately 248 miles (400 kilometers) offshore Western Australia. The FPU will be capable of being remotely operated and minimally staffed during normal production operations.
"McDermott brings the engineering and execution expertise to deliver integrated deepwater subsea projects and offshore FPUs to the highest standards," said Samik Mukherjee, Executive Vice President and Chief Operating Officer. "After a long engagement on the project, the collaborative execution model with Woodside—from pre-FEED through to EPCIC—de-risks execution. Further, the facilities incorporate energy efficiency in design to reduce Scarborough's offshore emissions."
The topside, which will be approximately 30,000 tons, will be fabricated by McDermott's joint venture fabrication yard, Qingdao McDermott Wuchuan, in China. The project scope includes a battery energy storage system to reduce emissions on the topsides and support Woodside's net emissions reduction targets.
"McDermott will apply our long history of successful integrated project delivery for the Scarborough Project, along with our deepwater expertise and industry-leading health and safety standards to drive this incredible project to completion," said Mahesh Swaminathan, Senior Vice President, Asia Pacific.
Engineering expertise will be leveraged from McDermott's Kuala Lumpur and Gurgaon offices, with McDermott's long-established subsea team in Perth supporting transport, installation, hook up and commissioning activities.
The FPU processes natural gas, which includes gas separation, dehydration and compression as well as mono ethylene glycol regeneration and produced-water handling. Designed for a production capacity of up to 1.8 billion standard cubic feet per day, the topside will be connected to the semi-submersible hull and pre-commissioned prior to transportation and installation in a water depth of 3,100 feet (950 meters), approximately 248 miles (400 kilometers) offshore Western Australia. The FPU will be capable of being remotely operated and minimally staffed during normal production operations.
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