The Ula Field is an offshore oil field located in the Norwegian North Sea. The project also serves as a production hub for the Tambar, Oda and Blane fields.
Ula, currently in its late life phase, is slated to produce until 2028 when the production licence is set to expire.
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Aker BP operates the field with 80% interest, while DNO Norge owns the remaining 20%.
As of 2021, Ula and Tambar have produced nearly 600 million barrels of oil equivalent. In 2022, Ula Field’s net production to Aker BP averaged 3 thousand barrels of oil equivalent per day (mboepd).
In August 2023, Aker BP proposed an Environmental Impact Assessment (EIA) Program to cease operations at the Ula and Tambar fields at the end of their production licences in 2028.
The EIA is aligned with the latest guidelines of Plan for Development and Operation (PDO) and the Plan for Operation and Development (POD) issued by the Norwegian Ministry of Petroleum and Energy in 2022.
Ula Location Details
The Ula Field is located in Block 7/12 in the Production License 019 (PL019) in the southern part of the Norwegian sector of the North Sea.
The water depth in the region is around 70m, while the reservoir is situated about 3,500m True Vertical Depth (TVD) Mean Sea Level (MSL).
Discovery and Key Milestones
The Ula Field was discovered by 7/12-2 discovery well in 1976. The well was drilled on a salt-induced structure, east of the Cod Terrace using the semi-submersible installation Norskald.
The well was drilled to a total depth of 3,676m in the Early Jurassic Gassum Formation.
Core analysis and log interpretation inferred a Ula Formation sandstone reservoir of 128m net thickness, with 14% to 28% porosities.
The porosity of the Gassum Formation sandstones was found to be between 11% and 19% with more than 70% water saturation.
Six drill stem tests were also carried out- Drill Stem Test 1 (DST 1) and DST 1a were performed in the Early Jurassic Gassum Formation and others were performed in the Late Jurassic Ula Formation.
The oil gravity was determined to be 40°API.
The Plan for Development and Operation (PDO) for the oil field was approved in 1980 and it commenced production in October 1986.
Aker BP has been operating the field since 2016.
Geology and Reserves
The main reservoir of the Ula Field is situated at a depth of 3,345m. It primarily produces oil from the Upper Jurassic Ula Formation sandstone, as well as from the Triassic reservoir situated below at 3,450m.
In 2015, a PDO for the Triassic reservoir was exempted by the Ministry of Petroleum and Energy of Norway.
The field had a total recoverable reserves of 550 million barrels of oil, 3.9 billion standard cubic metres (bscm) of gas, and 3.3 million tonnes of natural gas liquids (NGL).
As of December 2008, the North Sea asset had remaining reserves of 115 million barrels of oil and 0.8 million tonnes of NGL.
Initially, Ula was expected to produce 160 million barrels of oil over a period of 11 years. However, the field has already produced more than three times of the initial estimates.
Ula Field Development
The Ula Field development comprised three installations – the accommodation quarters (QP quarters), drilling (DP drilling), and production and processing platforms (PP processing platforms). The three facilities are connected via bridges.
Several modules are installed on each deck systems with each carrying a weight ranging from 7,700 tonnes to 10,700 tonnes.
DP drilling has six water injection wells and eight production wells, whereas the PP processing platform separates, compresses, and injects water.
Originally, the field produced by pressure injection. A few years later, water injection was adopted to improve the recovery.
In 1998, Water Alternating Gas (WAG) was introduced in order to produce more oil from the reservoir by alternating between injecting gas and water. All gas is reinjected into the reservoir to boost oil recovery.
Additional WAG wells were also drilled to support the programme.
The Tambar/Tambar East satellite fields are remotely controlled from Ula, while Oda and Blane are developed with subsea structures.
The WAG programme had been extended with gas from Tambar (2001), Blane (2007) and Oda (2019).
A new gas processing and injection module (UGU) doubled the gas capacity of Ula in 2008.
As of 2022, 49 wells were drilled at Ula. Out of these, nine were producing and four were injecting wells.
An export pipeline transports oil to the Ekofisk centre and Teesside in the UK. Until 1998, Ula transported gas to Ekofisk via Cod.
Decommissioning Plan
Initially, Aker BP planned to continue production from Ula Field until 2032.
However, the Cessation of Production (CoP) plan was changed to 2028 as the injection of additional gas was found to be non-economic. The production was also lower than expected in 2022 due to well issues.
The decreasing production indicates the asset will generate a possible negative cash flow in 2025.
The project also did not find new recoverable reserves in the nearby areas and installing a separate pipe for importing gas were found to be not economically feasible, thereby initiating a decommissioning plan.
The estimated date to terminate production is before the end of 2028, followed by the removal of installations.
According to the decommissioning plan, the plugging of wells will start in 2026/27.
The removal of facilities will be conducted in two campaigns which may take place in the summer of 2029 and the summer of 2030.
The seabed facilities will be removed by summer 2030.
Total liquidation costs, according to the preliminary estimates, will be between NOK8bn and NOK9bn ($720m and $800m).
The tie-in fields will also terminate production with the decommissioning of Ula field.
Key Recent Contracts
In December 2022, Aker BP awarded Aker Solutions a two-year extension contract for modification and maintenance work at Ula and other operated field centres.
In September 2019, Archer won a 15-month extension to its platform drilling and maintenance services contract for the Ula Field.
