From Norway (JS): Statoil is planning a slimmed down version of its Snøhvit (SEN, 31/22) subsea-to-beach development in the Barents Sea to tap the 620bcm of gas it has discovered off Tanzania.
The gas from Block 2 will be gathered by a subsea system and piped onshore to an LNG plant.
Harald Eliassen, offshore project director for Tanzania, told the Subsea Valley conference in Oslo that the company had looked at what it had done before on subsea-to-shore at Ormen Lange (32/02) and Snøhvit, both offshore Norway, to come up with a development solution.
‘We started out to create a subsea system very similar to Ormen Lange with large manifolds, dual pipelines, dual service lines, dual umbilicals, loads of redundancy – basically a copy ... for ultra-deepwater. But we soon realised this would be too expensive so we looked at Snøhvit and decided to make it even simpler than that.’
Statoil has now developed a system with a daisy chain layout with no manifolds and no large modules to be lifted. ‘We have simple in-line tees on the flowlines that we can connect each well to. It allows us to spread the xmas trees around on the seabed so that we get an easier well path and lower drilling costs,’ Eliassen said. ‘All of this made the system a lot cheaper and we managed to cut something like 30% off the cost from the original system we had.’
The project is now in the equipment selection phase and Statoil is looking at standardised solutions for the development.
‘We are looking at already proven solutions and we need to work together with industry and our partner Exxon (35%) to find out if there is anything out there we can use and copy and standardise, then we will do it. We will try to avoid as much technology development as possible.’
Eliassen stressed that the gas project is still in the early stages and there is a lot of work ahead on technical solutions for the onshore LNG plant, which will be built in conjunction with BG, which has made major gas finds in Blocks 1 and 4.
Statoil has drilled nine exploration wells, one combined exploration and appraisal well and three appraisal wells in Block 2 with the drillship Discoverer Americas, only two of which have been unsuccessful.
The discoveries, named after spices, are about 100km offshore in 2,200-2,500m. One of the deepest drillstem tests ever carried out in the world at 2,500m tested two zones and confirmed the production potential of Zafarani (32/02). It proved the reservoir connectivity and the extent of the reservoirs.
‘We think we can achieve a recovery factor of 60-80%,’ Eliassen added. ‘It depends on how much water support we get. We need some ... to keep the pressure up, but we don’t want the water breaking through into the production wells.’
He said the first phase will need 13-20 wells - Zafarani (5-7); Piri (3-5); Lavani Deep (2-3) and Lavani Main (3-5). ‘I think that’s what we are going to start with.’
Statoil is currently drilling the 14th well – the last well in the drilling campaign – the Tangawizi-2 appraiser.
‘If we can prove the reservoir to be feasible and economical to develop, we will probably add that to the production some 7-10 years after first gas and that will add another 5-8 wells to the development.’
The Giligalani, Mronge and Mdalsini finds will not be included in phase one as they are located in an area of difficult seabed terrain with steep seabed canyons and valleys around them.
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