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.

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.

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.

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

• 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.

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%).

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.

 

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%