E&P Notes (January 2022)
Authors: JPT staff _ 
Published: February 2022

Equinor To Give Oseberg a $1.1-Billion Lift
Equinor has filed an amended plan for development and operation (PDO) with Norway’s Minister of Petroleum and Energy to increase Oseberg gas production while reducing CO2 emissions from the Oseberg Field Centre and the Oseberg South platform.
The estimated $1.1-billion plan signals a shift in the Oseberg field from being an oil producer to becoming a natural gas producer with large remaining gas resources. Two new compressors will be installed to boost recoverable gas volumes and the Field Centre and South platform will be partially electrified.
“It is important to Equinor and the Oseberg partners to produce oil and gas with the lowest possible emission level,” said Geir Tungesvik, Equinor’s senior vice president for project development. “This investment decision allows us to increase production of Oseberg gas considerably in the future, while reducing CO2 emissions by an estimated 320,000 tonnes per year. We are now entering the execution phase with highly qualified suppliers.”
Aibel AS has been awarded a $443-million contract for engineering, procurement, construction, and installation for partial electrification of the Field Centre and South platform, as well as upgrading of the gas processing capacity on the Field Centre.
Nexans has been awarded a $88.6-million framework contract by Equinor for delivering subsea power cables. Its first assignment will be to deliver a 132-km cable, to be installed by the Nexans Aurora in 2023.
Heerema Marine Contractors has been awarded a contract for transport and installation at an estimated value of $6.6 million. In 2024, the Sleipnir vessel is scheduled for lifting in place the three big modules currently under construction at Aibel’s yard in Haugesund.
Equinor said rebuilding of the Field Centre will take 4 years and will be done while the plants are in full operation. Startup of the new facility is expected in 2026.
Oseberg is the third-largest oil producer ever on the Norwegian Continental Shelf (NCS). When it came on stream in 1988, it was expected to produce around 1 billion bbl of oil. Today, that number is expected to total around 3.2 billion bbl. Oil production is in the tail phase, but 60% of the gas resources are still in the ground. Oseberg is also one of the major gas fields; only Troll and Snøhvit have more remaining gas resources on the NCS.
“With this investment we open a new chapter of the story of Oseberg, which is about to become one of the main Norwegian gas producers,” said Geir Sørtveit, Equinor’s senior vice president for exploration and production west. “We expect Oseberg to produce more than 100 billion sm3 of gas towards 2040. In terms of energy, the annual gas export from Oseberg will equal a quarter of all Norwegian hydropower.”
For the year 2020, Oseberg emissions totaled around 1 million tonnes of CO2. Since 2010, emissions have been reduced by around 15%, and Equinor aims to further reduce emissions by 50–70% by 2030.
Equinor is the operator with a 49.3% stake. Partners include Petoro (33.6%), TotalEnergies EP Norge (14.7%), and ConocoPhillips (2.4%).

Shell Scraps Cambo Development Plans
Shell has abandoned plans to develop the Cambo oil field in the UK North Sea. The field had been a target of controversy for opponents that claim the project is at odds with the UK’s goal of reaching carbon neutrality by 2050.
“After comprehensive screening of the proposed Cambo development, we have concluded the economic case for investment in this project is not strong enough at this time, as well as having the potential for delays,” a Shell spokesperson said in a statement.
Private-equity-backed Siccar Point Energy, which owns a majority stake in the field, confirmed in a separate statement that “Shell has taken the decision to not progress its investment at this stage.”
The Cambo project off the Shetland Isles is estimated to hold around 170 million bbl of oil and associated gas.
Shell holds a 30% working interest in Cambo; Siccar Point holds the remaining 70% stake.

CNOOC Turns the Taps at Lufeng
CNOOC Ltd. has started production from its Lufeng oil fields in the Eastern South China Sea. The field cluster includes Lufeng 14-4, Lufeng 14‑8, Lufeng 15-1, and Lufeng 22-1, with an average water depth of about 140–330 m. The main production facilities include two drilling production platforms and one subsea production system. Thirty-five development wells are planned to be put into production, including 26 production wells and 9 water injection wells. The project is expected to achieve its peak production of around 46,000 B/D of oil in 2023.
CNOOC Ltd. owns 100% interest in the project.

Lukoil Touts Find Offshore Mexico
Lukoil has struck Miocene-aged oil sands with its Yoti West exploration well in Block 12 offshore Mexico. The initial oil in place is estimated to be around 250 million bbl. The Yoti West-1 EXP well was drilled 60 km offshore by the Valaris 8505 semisubmersible drilling rig. The well penetrated a sand reservoir in Upper Miocene sediments with high permeability and effective oil-saturated thickness of about 25 m. An assessment plan for the field will be developed based on this and future drilling results.
Lukoil Upstream Mexico is the operator and holds a 60% working interest in the block. Partner Eni holds the remaining 40% stake.
Two successful exploration wells were previously drilled at Block 10 offshore Mexico where Lukoil owns 20% and Eni is the operator. The resource base of the block is currently being assessed based on drilling results.
In July, Lukoil agreed to acquire the 50% operator interest held by Houston-based Fieldwood Energy in Mexico’s Area 4 offshore shallow-water project for $435 million, plus 2021 expenditures incurred up to the closing date of the transaction. Area 4 includes two blocks, 58 km2 in total, located 42 km offshore in water depths of 30–45 m. The Ichalkil and Pokoch oil fields within the blocks have recoverable reserves of 564 million BOE, of which 80% is crude oil.

Petrobras Strikes Oil in Aram Block
Petrobras encountered hydrocarbons with its Curaçao pre-salt well in the Aram block of the Santos Basin. Well 1-BRSA-1381-SPS is located at a water depth of 1905 m, 240 km from the city of Santos, Sao Paulo. The oil-bearing interval was verified through wireline logging and fluid samples, which will be further characterized by lab analysis.
The data will allow evaluating the potential and directing the next exploratory activities in the area. The consortium will continue operations to complete the project to drill the well to the expected depth and verify the extent of the new discovery, in addition to characterizing the conditions of the reservoirs found.
The Aram block was acquired in March 2020 in the 6th Bidding Round of the National Agency for Petroleum, Natural Gas, and Biofuels (ANP) under the production-sharing regime, with Pre-Sal Petróleo as manager. Petrobras is the operator of the block and holds an 80% share, in partnership with CNODC (20%).

APA Takes Good With Bad on Block 58 in Suriname
APA Corp. reported a successful flow testing at the Sapakara South appraisal well and disappointing drilling results from the Bonboni exploration well on Block 58 offshore Suriname.
The company said earlier in 2021 that the Sapakara South-1 (SPS-1) well encountered approximately 30 m of net black-oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. Restricted flow and subsequent pressure buildup tests averaged 4,800 B/D of oil for 48 hours. Without flow restrictions, a development well would produce at a significantly higher sustained rate, according to APA.
Preliminary analysis of the data indicates a single reservoir in SPS-1 proved a connected resource of 325 to 375 million bbl of oil in place. Seismic imaging of the Sapakara reservoir supports the likelihood of more potential, said APA.
The Bonboni-1 probe, the first exploration well in the northern portion of Block 58, was drilled in water depths of nearly 2000 m approximately 45 km from APA’s discoveries in the Maka-Kwaskwasi-Sapakara-Keskesi trend and encountered high-quality, water-bearing reservoirs in the primary Maastrichtian and Campanian objectives. The well will be plugged and abandoned. APA said that while the well wasn’t commercial, it extended the proved petroleum system in the area.
Following completion of operations at Bonboni, the Maersk Valiant will drill the Krabdagu exploration prospect, located 18 km east of SPS-1. Krabdagu has a similar seismic signature to the two successful wells at Sapakara and the discovery well at nearby Keskesi. Success at Krabdagu could materially increase the scope and scale of a development in the central portion of Block 58. The company envisions a potential black-oil development hub that would accommodate production from Krabdagu, Sapakara, and Keskesi.
APA Suriname holds a 50% working interest in the block, with TotalEnergies, the operator, holding the remaining 50% stake.

Tullow To Exit Suriname
Tullow Oil will leave Suriname following subpar results from its Goliathberg Voltzberg North-1 (GNV-1) well in Block 47 in the region. The well was drilled by drillship Stena Forth targeting more than 230 million bbl of oil. However, the well encountered only minor oil shows. Tullow and its partners notified the Government of Suriname that they have elected not to enter the next phase of Block 47, and the company confirmed it would exit the license on 31 December 2021.
Prior to drilling, the block was estimated to contain more than 900 million bbl of oil in three different prospects, including Goliathberg Voltzberg North. Tullow operates the block with a 50% stake. Partners include Pluspetrol (30%) and Ratio Petroleum (20%).
In addition, Tullow said it will exit Block 54 at year-end. In 2017, Tullow drilled the Araku-1 well in Block 54 but did not find commercial hydrocarbons. The move leaves the company without assets or operations in the country.