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).
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