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Operations Johan Sverdrup

The Johan Sverdrup discovery is one of the largest oil discoveries ever made on the Norwegian continental shelf and will prolong the life of the Norwegian oil industry for several decades. The discovery extends over an area of approximately 200 km² on the Utsira High in the central part of the North Sea.

Johan Sverdrup
Example of Johan Sverdrup field topsides layout
The Johan Sverdrup field is located 155 km west of Stavanger. The field was discovered in 2010 with the discovery on the Avaldsnes prospect in PL501 by Lundin Norway followed by the discovery of Aldous in PL265 by Statoil in 2011. The discovery of Johan Sverdrup was a direct result of the Edvard Grieg discovery made by Lundin Norway in 2007, as the Johan Sverdrup play concept was modelled on the same basis as that for Edvard Grieg.

PDO approval
The Plan of Development and Operation (PDO) for the giant Johan Sverdrup field was submitted to the Norwegian Ministry of Petroleum and Energy (the Ministry) in February 2015. Following Norwegian Parliament approval in June 2015, the PDO for Phase 1 was given final approval by the Ministry in August 2015.

Reserves and production
Following the execution of the Johan Sverdrup unit operating agreement and the approval of the PDO, Lundin Petroleum has booked net 2P reserves of 515 MMboe for the full field development, based on Lundin Petroleum's 22.60 percent working interest. The gross 1P and 3P reserves for the full field development are estimated to be 1.65 and 3.02 billion boe respectively. These volumes expressed in boe include oil, gas and natural gas liquids and comprise approximately 95 percent oil. The reserves have been independently audited by ERC Equipoise Ltd.

The oil and gas production capacity for the full field is expected to be in the range of 550,000 - 650,000 barrels of oil equivalent per day. This makes Johan Sverdrup one of the five largest fields ever discovered on the Norwegian continental shelf. When the full field plateau production is reached, Johan Sverdrup is likely to represent around 25 percent of all Norwegian oil and gas production.

Phased development
The Johan Sverdrup field will be developed in several phases and with multiple fixed platform installations. Phase 1 of the development consists of four bridge linked platforms as well as three subsea installations. The gross capital expenditures for Phase 1 is estimated at NOK 117 billion (real 2015) which includes oil and gas export pipelines, development wells as well as power supply from shore.

Phase 1 is scheduled to start production in late 2019 with a forecast gross production level of between 315,000 and 380,000 barrels of oil per day. Phase 1 will consist of 35 production and injection wells of which 14 to 15 wells will be drilled prior to first oil.

Phase 2 of the Johan Sverdrup development is expected to commence production in 2022. Whilst the development concept for the full field development has not yet been approved by the partnership, the current estimated full field capital costs, including Phase 1 costs, are in the range of NOK 170 to NOK 220 billion (real 2015).

Export pipeline
The Johan Sverdrup oil and gas production will be transported to shore via dedicated oil and gas pipelines. A 274 km 36" oil pipeline will be installed and connected to the Mongstad oil terminal on the west coast of Norway. A 165 km 18" gas pipeline will be installed and connected to the Kårstø gas terminal for processing and onward transportation.

Lundin Norway has a 22.60 percent working interest in the Johan Sverdrup field. Statoil is operator with 40.0267 percent and the remaining partners are Maersk Oil with 8.44 percent, Petoro with 17.36 percent and Det norske oljeselskap with 11.5733 percent working interest.

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Facts about the Johan Sverdrup field
The field centre for the Johan Sverdrup field in the first phase will consist of four installations. The installations have steel jackets and will be connected by bridges. The water depth is approximately 110 metres.
Process platform

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The process platform has all the processing capacity for the entire field centre. Separation and injection systems. Gas, oil and injection water are transported by pipeline to a riser platform.

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Designed for a capacity of 315,000 to 380,000 barrels of oil equivalents (50,000- 60,000 standard cubic metres).

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The platform deck has three modules with two separation trains for oil and gas separation, cleaning of produced water, gas treatment and utility systems. Supported by an eight-leg steel jacket, the platform deck is 100 metres long and 23 metres wide, and the weight is estimated at 26,300 tonnes.
Drilling platform

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The field centre is planned to be developed with an integrated drilling facility. This concept was selected on the basis of seabed conditions and number of wells from the field centre.

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The platform deck consists of 48 slots, well intervention deck and manifolds.

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Predrilling is performed by a semi-submersible drilling rig through a predrilling template.

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The estimated weight is 21,500 tonnes dry weight. Size: 40 metres x 83 metres.
Riser platform

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This is the centre for export of processed oil and gas, as well as the centre for incoming volumes from future tie-backs from satellite fields.The platform is designed with 45 risers and J-tubes.

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Water injection and oil export pumps are also localised here.

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The platform has a converter module (DC/AC) for power from shore.

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In the first phase, the platform consists of three modules. Large sections of the weather decks on these modules have been designed so as to enable future installation of IOR (improved oil recovery) modules and/or handle increased production from future development phases.

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The dry weight of the platform deck is approximately 21,800 tonnes in the first phase and is ca. 125 metres long and 30 metres wide.
Living quarters

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The platform deck consists of the living quarter itself, withprovision for 550 personnel.

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The helideck and lifeboats are also localised here.

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The size is 85 x 28 metres, and it is supported by a four-leg steel jacket.

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The weight is approximately 19,500 tonnes.
Transport solutions

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The oil will be transported to the Mongstad terminal in the county of Hordaland by a 274 km long, 36-inch diameter pipeline.

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The project includes landing and alignment and modifications to the Mongstad terminal.

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The gas will be transported to Kårstø in the county of Rogaland for processing and further transport.

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The pipeline will be 165 km long, with an 18-inch diameter. It will be tied into the Statpipe system by means of a subsea tie-back (hot tap).

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The tie-back point is located approximately 10 km west of Karmøy.
The reservoir

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Gross 1P and 3P reserves for the full field development are estimated to be 1.65 and 3.02 billion boe

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The reservoir spans more than 200 square kilometres.

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The reservoir is at a depth of approximately 1800 - 1900 metres beneath the seabed.

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The reservoir properties are very good and characterised by good flow properties. Normal pressure and normal temperature (hydrostatic).

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Requires pressure support from water injection. The oil in the field is of a quality known as «medium oil» at 28 API.
Wells

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Total amount of wells in Phase 1 is 35 both production and injection wells, full field total 77 wells

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14 – 15 wells (both production and injection) will be pre-drilled from 2016 for speedy production

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Water injection templates are scheduled from start because pressure support is necessary from production startup. Water injection has been chosen.
Johan Sverdrup
 
     

FRANCE


» 20 licences
  - 15 production
  -  5 exploration
» Net reserves 19.1 MMboe

NORWAY


» 64 licences
  - 8 production
  - 2 development
  - 54 exploration
» Net reserves 684.5 MMboe

NETHERLANDS


» 20 licences
  -  18 production
  -  2 exploration
» Net reserves 1.9 MMboe

RUSSIA


» 1 development licence
 

MALAYSIA


» 6 licences
   - 1 production
   - 5 exploration
» Net reserves 10.7 MMboe