Development of a Large Deep-Water Gas Field in Tanzania: Subsurface Challenges and Solutions in a Frontier Area
- Einar Haugen (Equinor) | Sabina Solymar (Equinor) | Severine Pannetier-Lescoffit (Equinor) | Kari Reksten (Equinor) | Ida Winsnes Lund (Equinor) | Zoran Mrsic (Equinor)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 24-26 September, Dallas, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 4.2 Pipelines, Flowlines and Risers, 5.1.8 Seismic Modelling, 4.2 Pipelines, Flowlines and Risers, 4.6 Natural Gas Conversion and Storage, 1.10 Drilling Equipment, 4.6.2 Liquified Natural Gas (LNG), 7 Management and Information, 7.2.1 Risk, Uncertainty and Risk Assessment, 4.6 Natural Gas, 7.2 Risk Management and Decision-Making, 4 Facilities Design, Construction and Operation, 4.3 Flow Assurance, 1.10 Drilling Equipment
- gas reservoir, Tanzania, deep water
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Significant gas discoveries have been made in deep waters off the coast of Tanzania this decade. Operator Equinor (previously Statoil) with co-venturer ExxonMobil have drilled 15 exploration and appraisal wells in Block 2 about 100 km from the shore in the southern part of the country. The objective is to develop gas resources for a large LNG project. This paper focuses on the various discoveries made and the subsurface understanding gained over the last years.
The reservoirs are all deposited as turbiditic sandstones in different geologic periods (Cretaceous to Miocene), and have a long and complicated geological history. Heavy tectonic activity including development of pop-up structures along a major strike-slip system, has impacted the depositional environment. Since some of the reservoirs have significant internal faulting, methods to analyze fault transmissibility have been key. The seismic quality is generally good, and in certain reservoirs even good enough to directly use seismic inversion dataset to map the structure more accurately. The exploration and subsurface teams worked together in improving the development concept and minimizing risk.
The youngest reservoir (Miocene) has excellent reservoir properties but special challenges with shallow overburden with top reservoir 400-500 m below the seafloor. Several studies have been completed to ensure that production wells can be safely drilled and produced during reservoir depletion, and that the reservoir seal has full integrity.
In deep water oil and gas developments it is important to demonstrate large, continuous flow units with good flow properties before investment decisions. For the Block 2 gas reservoirs understanding the aquifer strength is important for designing wells so that water production can be avoided. Detailed aquifer modeling has been made for all the main reservoirs. Modelling showed risk of water production for one of the reservoirs; however, it is expected that this risk can be mitigated by placing the planned producers high on the structure.
Deep seabed canyons are present in the area and these give important constraints on drilling locations and subsea layout including the major gas pipeline to shore. The field development is planned as a subsea-to-shore development without any fixed installations offshore. To predict the dynamic performance of such a huge and complex production system, extensive flow assurance studies have been completed.
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